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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS1


Filed Pursuant to Rule 424(b)(3)
Registration No. 333-197341


Table of Contents

PROSPECTUS

LOGO

NGL Energy Partners LP
NGL Energy Finance Corp.

Offer to Issue
Up to $450,000,000 of
6.875% Senior Notes due 2021

That Have Been Registered Under
the Securities Act of 1933
("new notes")
In Exchange For

Up to $450,000,000 of
6.875% Senior Notes due 2021

That Have Not Been Registered Under
the Securities Act of 1933
("old notes")

Terms of the New Notes:

Terms of the Exchange Offer:



        You should carefully consider the risks set forth under "Risk Factors" beginning on page 11 of this prospectus for a discussion of factors you should consider before participating in the exchange offer.



        Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.



   

The date of this prospectus is January 13, 2015.


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        This prospectus is part of a registration statement we filed with the Securities and Exchange Commission. In making your investment decision, you should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. If you receive any unauthorized information, you must not rely on it. We are not making an offer to sell these securities or soliciting an offer to buy these securities in any jurisdiction where an offer or solicitation is not authorized or in which the person making that offer or solicitation is not qualified to do so or to anyone whom it is unlawful to make an offer or solicitation. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus.


TABLE OF CONTENTS

 
  Page  

WHERE YOU CAN FIND MORE INFORMATION

    ii  

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

    iii  

PROSPECTUS SUMMARY

    1  

RISK FACTORS

    11  

EXCHANGE OFFER

    33  

RATIO OF EARNINGS TO FIXED CHARGES

    41  

USE OF PROCEEDS

    42  

SELECTED CONSOLIDATED HISTORICAL FINANCIAL AND OPERATING DATA

    43  

BUSINESS

    44  

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

    71  

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

    137  

MANAGEMENT

    139  

EXECUTIVE COMPENSATION

    145  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

    156  

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

       

DESCRIPTION OF NOTES

    159  

PLAN OF DISTRIBUTION

    218  

CERTAIN U.S. FEDERAL INCOME TAX CONSEQUENCES

    219  

LEGAL MATTERS

    220  

EXPERTS

    220  

INDEX TO FINANCIAL STATEMENTS

    F-1  

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WHERE YOU CAN FIND MORE INFORMATION

        Our SEC filings will be available to the public over the Internet at the SEC's web site at http://www.sec.gov. You may also read and copy any document we file at the SEC's public reference room located at 100 F Street, N.E., Washington D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room and copy charges. We will provide you upon request, without charge, a copy of the notes and the indenture governing the notes. You may request copies of these documents by contacting us at:

NGL Energy Partners LP
6120 South Yale Avenue
Suite 805
Tulsa, Oklahoma 74136
(918) 481-1119

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CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS

        This prospectus contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this prospectus, words such as "anticipate," "believe," "could," "estimate," "expect," "forecast," "goal," "intend," "may," "plan," "project," "will," and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our general partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. The following are key risk factors that may impact our consolidated financial position and results of operations:

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        All readers are cautioned that the forward-looking statements contained in this prospectus are not guarantees of future performance, and our expectations may not be realized or the forward-looking events and circumstances may not occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described elsewhere in this prospectus, including under the heading "Risk Factors" in this prospectus. You should not put undue reliance on any forward-looking statements. All forward-looking statements included in this prospectus are made only as of the date hereof. Except as required by state and federal securities laws, we undertake no obligation to update or revise any forward-looking statements as a result of information, future events or otherwise.

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PROSPECTUS SUMMARY

        This summary highlights information included in this prospectus. It does not contain all of the information that may be important to you. You should read carefully this entire prospectus for a more complete understanding of our business and the terms of this offering, as well as the tax and other considerations that are important to you in making your investment decision.

        Unless the context otherwise requires, references to "NGL Energy Partners," "NGL," "we," "us," "our" and similar terms, as well as references to the "Partnership," are to NGL Energy Partners LP and all of its subsidiaries. Our "general partner" refers to NGL Energy Holdings LLC.


NGL Energy Partners LP

Overview

        We are a Delaware limited partnership formed in September 2010 by several investors. As part of our formation, we acquired and combined the assets and operations of NGL Supply, Inc., primarily a wholesale propane and terminalling business founded in 1967, and Hicksgas, LLC and Hicksgas Gifford, Inc., primarily a retail propane business founded in 1940. Subsequent to our formation, we significantly expanded our operations through numerous business combinations, including with High Sierra Energy, LP in 2012, as a result of which we entered the crude oil logistics and water services businesses, and Gavilon, LLC in December 2013, as a result of which we entered the refined products marketing and renewables businesses.

        At September 30, 2014, our operations include:

 

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Our Ownership and Organizational Structure

        The following chart provides a simplified overview of our organizational structure as of September 30, 2014:

GRAPHIC


(1)
The notes are currently guaranteed by all of our restricted subsidiaries (other than NGL Energy Finance Corp.) that are obligors under certain of our indebtedness, including our Credit Agreement. See "Description of Notes—Note Guarantees" and "—Additional Note Guarantees."

(2)
Includes (i) NGL Crude Logistics, LLC which includes the operations of our crude oil logistics, refined products and renewables business, (ii) NGL Water Solutions, LLC, which includes the operations of our water solutions business, (iii) NGL Liquids, LLC, which includes the operations of our liquids business and (iv) NGL Propane, LLC, which includes the operations of our retail propane business.

 

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        On November 26, 2014, NGL Crude Terminals, LLC ("NGL Crude"), a subsidiary of NGL Energy Partners LP (the "Partnership"), entered into a Membership Interest Purchase Agreement (the "Purchase Agreement") with Rimrock Midstream, LLC ("Rimrock"), its 50% joint venture partner in the ownership of Grand Mesa Pipeline, LLC ("Grand Mesa"). Pursuant to the Purchase Agreement, NGL Crude agreed to acquire from Rimrock the remaining 50% membership interest in Grand Mesa in exchange for $310.0 million in cash. The Purchase Agreement contains provisions regarding contingencies as well as customary representations and warranties, covenants and agreements. NGL Crude completed the purchase on December 1, 2014.

        On December 1, 2014, NGL Energy Operating, LLC, in its capacity as borrowers' agent and a wholly-owned subsidiary of the Partnership, entered into a Facility Increase Agreement (the "Agreement") with Deutsche Bank Trust Company Americas, as administrative agent and the other financial institutions party thereto. The Agreement increases the working capital revolving commitments under the Partnership's revolving credit facility by an additional $103.0 million.

        We are a limited partnership formed under the laws of the State of Delaware. Our executive offices are located at 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma 74136. Our telephone number is (918) 481-1119. We maintain a website at http://www.nglenergypartners.com. Information contained on this website, however, is not incorporated into or otherwise a part of this prospectus.

 

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The Exchange Offer

        On October 16, 2013 we completed a private offering of the old notes. We entered into a registration rights agreement with the initial purchasers in the private offering pursuant to which we agreed to deliver to you this prospectus and to use commercially reasonable efforts to cause the registration statement of which his prospectus forms a part to be declared effective by the SEC on or before October 16, 2014.

Old Notes

  $450 million aggregate principal amount of 6.875% Senior Notes due 2021, issued pursuant to Rule 144A and Regulation S promulgated under the Securities Act. Transfer restrictions apply to the old notes.

New Notes

 

Up to $450 million aggregate principal amount of 6.875% Senior Notes due 2021. The terms of the new notes are identical to the terms of the old notes, except that the new notes will be registered under the Securities Act, and will not have restrictions on transfer, registration rights or provisions for additional interest.

 

Except as provided below, we believe that the new notes may be offered for resale, resold and otherwise transferred by you without compliance with the registration and prospectus delivery provisions of the Securities Act provided that:

 

the new notes are being acquired in the ordinary course of business,

 

you are not participating, do not intend to participate, and have no arrangement or understanding with any person to participate in the distribution of the new notes issued to you in the exchange offer,

 

you are not our affiliate, and

 

you are not a broker-dealer tendering old notes acquired directly from us for your account.

 

Our belief is based on interpretations by the staff of the SEC, as set forth in no-action letters issued to third parties that are not related to us. The SEC has not considered this exchange offer in the context of a no-action letter, and we cannot assure you that the SEC would make similar determinations with respect to this exchange offer. If any of these conditions are not satisfied, or if our belief is not accurate, and you transfer any new notes issued to you in the exchange offer without delivering a resale prospectus meeting the requirements of the Securities Act or without an exemption from registration of your new notes from those requirements, you may incur liability under the Securities Act. We will not assume, nor will we indemnify you against, any such liability. Each broker-dealer that receives new notes for its own account in exchange for old notes, where the old notes were acquired by such broker-dealer as a result of market-making or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. See "Plan of Distribution."



   

 

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Exchange Offer

 

We are offering to issue freely tradable new notes in exchange for the same principal amount of old notes. The old notes may be tendered only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. We will issue new notes in exchange for all old notes that are validly tendered and not withdrawn prior to the expiration of the exchange offer. We will cause the exchange to be effected promptly after the expiration date of the exchange offer.

 

The new notes will evidence the same debt as the old notes and will be issued under and entitled to the benefits of the same indenture that governs the old notes. Because we have registered the offers and sales of the new notes, the new notes will not be subject to transfer restrictions, and holders of old notes that have tendered and had their outstanding notes accepted in the exchange offer will have no further registration rights.

Expiration Date

 

The exchange offer will expire at 12:00 midnight, New York City time, at the end of February 10, 2015, unless we decide to extend it.

Conditions to the Exchange Offer

 

The registration rights agreement does not require us to accept old notes for exchange if the exchange offer, or the making of any exchange by a holder of the old notes, would violate any applicable law or interpretation of the staff of the Securities and Exchange Commission. The exchange offer is not conditioned on a minimum aggregate principal amount of old notes being tendered. Please read "Exchange Offer—Conditions to the Exchange Offer" for more information about the conditions to the exchange offer.

Procedures for Tendering Old Notes

 

To participate in the exchange offer, you must follow the procedures established by The Depository Trust Company, or DTC, for tendering notes held in book-entry form. These procedures for using DTC's Automated Tender Offer Program, or ATOP, require that (i) the exchange agent receive, prior to the expiration date of the exchange offer, a computer generated message known as an "agent's message" that is transmitted through ATOP, and (ii) DTC confirms that:

 

DTC has received your instructions to exchange your notes; and

 

you agree to be bound by the terms of the letter of transmittal.

 

By transmitting an agent's message, you will represent to us that, among other things:

 

the new notes you receive will be acquired in the ordinary course of your business;

 

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you are not participating, and you have no arrangement with any person or entity to participate, in the distribution of the new notes;

 

you are not our "affiliate," as defined in Rule 405 under the Securities Act, or a broker-dealer tendering old notes acquired directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act; and

 

if you are not a broker-dealer, that you are not engaged in and do not intend to engage in the distribution of the new notes.

 

For more information on tendering your old notes, please refer to the section in this prospectus entitled "Exchange Offer—Terms of the Exchange Offer," "—Procedures for Tendering," and "Description of Notes—Book-Entry, Delivery and Form."

Guaranteed Delivery Procedures

 

None.

Withdrawal of Tenders

 

You may withdraw your tender of old notes at any time prior to the expiration date. To withdraw, you must submit a notice of withdrawal to the exchange agent using ATOP procedures before 12:00 midnight, New York City time, at the end of the expiration date of the exchange offer. Please refer to the section in this prospectus entitled "Exchange Offer—Withdrawal of Tenders."

Acceptance of Old Notes and Delivery of New Notes

 

If you fulfill all conditions required for proper acceptance of old notes, we will accept any and all old notes that you properly tender in the exchange offer on or before 12:00 midnight, New York City time, at the end of the expiration date. We will return any old notes that we do not accept for exchange to you without expense promptly after the expiration date and acceptance of the old notes for exchange. Please refer to the section in this prospectus entitled "Exchange Offer—Terms of the Exchange Offer."

Fees and Expenses

 

We will bear expenses related to the exchange offer. Please refer to the section in this prospectus entitled "Exchange Offer—Fees and Expenses."

Use of Proceeds

 

The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement entered into in connection with the initial issuance of the old notes.

 

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Consequences of Failure to Exchange Old Notes

 

If you do not exchange your old notes in this exchange offer, you will no longer be able to require us to register the old notes under the Securities Act, except in limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the old notes unless we have registered the old notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.

U.S. Federal Income Tax Considerations

 

The exchange of old notes for new notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read "Certain U.S. Federal Income Tax Consequences."

Exchange Agent

 

We have appointed U.S. Bank National Association as exchange agent for the exchange offer. You should direct questions and requests for assistance, as well as requests for additional copies of this prospectus or the letter of transmittal, to the exchange agent addressed as follows: U.S. Bank National Association, Corporate Trust Services, Attention: Specialized Finance Department, 111 Fillmore Ave. E., St. Paul, MN 55107. Eligible institutions may make requests by facsimile at (651) 466-7367, and may confirm facsimile delivery by calling (800) 934-6802.

 

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Terms of the New Notes

        The new notes will be identical to the old notes, except that the new notes are registered under the Securities Act and will not have restrictions on transfer, registration rights or provisions for additional interest. The new notes will evidence the same debt as the old notes, and the same indenture will govern the new notes and the old notes.

        The following summary contains basic information about the new notes and is not intended to be complete. It does not contain all the information that is important to you. For a more complete understanding of the new notes, please refer to the section of this prospectus entitled "Description of Notes."

Issuers

  NGL Energy Partners LP and NGL Energy Finance Corp.

 

NGL Energy Finance Corp., a Delaware corporation, is a 100% owned subsidiary of NGL Energy Partners LP that was organized for the sole purpose of being a co-issuer of certain of our indebtedness, including the new notes. NGL Energy Finance Corp. has no operations and no revenue other than as may be incidental to its activities as co-issuer of our indebtedness.

Notes Offered

 

$450 million aggregate principal amount of 6.875% Senior Notes due 2021.

Maturity Date

 

October 15, 2021.

Interest

 

Interest on the new notes will accrue from April 15, 2014 at a rate of 6.875% per annum (calculated using a 360-day year).

 

Interest on the new notes is payable on April 15 and October 15 of each year.

Ranking

 

Like the old notes, the new notes will be the unsecured senior obligations of each of the Issuers. Accordingly, they will rank:

 

pari passu in right of payment with all existing and future unsecured senior indebtedness of each of the Issuers;

 

senior in right of payment to any future subordinated indebtedness of each of the Issuers;

 

structurally subordinated to all obligations of any of our subsidiaries; and

 

effectively junior in right of payment to all existing and future secured indebtedness of each of the Issuers, including indebtedness under the our revolving credit agreement (the "Credit Agreement") and our 6.65% Senior Secured Notes due 2022 (the "Existing Senior Secured Notes"), which are secured by substantially all of the assets of NGL Energy, to the extent of the value of the assets of the Issuers constituting collateral securing such indebtedness.

 

See "Risk Factors—Risks Related to the Notes—The notes and the guarantees are unsecured and effectively subordinated to our and our subsidiary guarantors' existing and future secured indebtedness.."

 

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As of September 30, 2014, we had $2,442.4 million of total long-term indebtedness, $1,329.5 million of which was secured indebtedness, and we had $904.3 million of remaining borrowing capacity under our Credit Agreement (net of $209.2 million of outstanding letters of credit).

 

The guarantees will rank:

 

pari passu in right of payment with all existing and future unsecured senior indebtedness of each guarantor;

 

senior in right of payment to any future subordinated indebtedness of each guarantor; and

 

effectively junior in right of payment to all existing and future secured indebtedness of each guarantor, including indebtedness under the Credit Agreement and the Existing Senior Secured Notes, to the extent of the value of the assets of each guarantor constituting collateral securing such indebtedness.

Optional Redemption

 

Beginning on October 15, 2016, we may redeem some or all of the new notes at the redemption prices listed under "Description of Notes—Optional Redemption" plus accrued and unpaid interest, if any, on the notes to the date of redemption.

 

At any time prior to October 15, 2016, we may, at our option, redeem up to 35% of the new notes with a cash amount equal to the net proceeds of certain equity offerings at a redemption price equal to 106.875% of the aggregate principal amount, plus accrued and unpaid interest, if any, to the redemption date. We may make that redemption only if, after the redemption, at least 65% of the aggregate principal amount of the new notes issued on the initial issue date remains outstanding and the redemption occurs within 180 days of the closing of the equity offering. Please see "Description of Notes—Optional Redemption."

 

We may, from time to time prior to October 15, 2016, redeem all or a part of the new notes, at a redemption price equal to 100% of the aggregate principal amount of the new notes redeemed, plus a "make-whole" premium and accrued and unpaid interest, if any, to the redemption date.

Change of Control

 

If we experience certain kinds of changes of control, we must give holders of the new notes the opportunity to sell us their new notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

Certain Covenants

 

The indenture governing the new notes contains certain covenants limiting our ability and the ability of our restricted subsidiaries to, under certain circumstances:

 

pay distributions on, purchase or redeem our common equity or purchase or redeem our subordinated debt;

 

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incur or guarantee additional indebtedness or issue preferred units;

 

create or incur certain liens;

 

enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

 

consolidate, merge or transfer all or substantially all of our assets; and

 

engage in transactions with affiliates.

 

These covenants are subject to important exceptions and qualifications as described in this prospectus under the caption "Description of Notes—Covenants." In addition, certain of the covenants listed above will terminate before the new notes mature if any two of the three specified rating agencies assign the new notes an investment grade rating in the future and no events of default exist under the indenture. Any covenants that cease to apply to us as a result of achieving investment grade ratings will not be restored, even if the credit ratings assigned to the new notes later fall below investment grade.

Absence of Established Market for the New Notes

 

The new notes generally will be freely transferable, but will also be new securities for which there will not initially be a market. There can be no assurance as to the development or liquidity of any market for the new notes.

 

We do not intend to apply for a listing of the new notes on any securities exchange or for the inclusion of the new notes on any automated dealer quotation system.

Ratio of Earnings to Fixed Charges

        The following table presents the ratios of earnings to fixed charges of the Partnership for the periods indicated. For purposes of computing the ratios of earnings to fixed charges, earnings consist of income (loss) from continuing operations before income taxes plus fixed charges and loss (income) from continuing operations before income taxes attributable to noncontrolling interests. Fixed charges consists of interest expense plus loss on early extinguishment of debt and the portion of rental expense estimated to relate to interest. The portion of rental expense estimated to relate to interest represents one-third of total operating lease rental expense, which is the portion estimated to represent interest.

 
  NGL Energy Partners LP   NGL Supply, Inc.  
 
  Six
Months
Ended
September 30,
2014
  Year
Ended
March 31,
2014
  Year
Ended
March 31,
2013
  Year
Ended
March 31,
2012
  Six
Months
Ended
March 31,
2011
  Six
Months
Ended
September 30,
2010
  Year
Ended
March 31,
2010
 

Ratio of earnings to fixed charges

             (a)   1.53x     1.75x     1.91x     5.59x              (b)   6.32x  

(a)
Due to NGL Energy Partners LP's loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2014. NGL Energy Partners LP would have needed to generate an additional $60.1 million of earnings to achieve a ratio of 1:1.

(b)
Due to NGL Supply, Inc.'s loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2010. NGL Supply, Inc. would have needed to generate an additional $3.9 million of earnings to achieve a ratio of 1:1.

 

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RISK FACTORS

        An investment in the notes is subject to numerous risks, including those listed below. You should carefully consider the following risks as well as the information provided elsewhere in this prospectus. While these are the risks and uncertainties we believe are most important for you to consider, you should know that they are not the only risks or uncertainties facing us or which may adversely affect our business. These risks could materially affect our ability to meet our obligations under the notes. You could lose all or part of your investment in and fail to achieve the expected return on the notes

Risks Related to Investing in the New Notes

         Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects and our ability to make payments on the notes.

        As of September 30, 2014, we had $2,442.4 million of total long-term indebtedness, including $1,079.5 million of debt outstanding under our Credit Agreement and approximately $250 million aggregate principal amount of our senior secured notes, and we had additional borrowing capacity of $904.3 million under our Credit Agreement (net of $209.2 million of outstanding letters of credit). Our level of indebtedness could affect our operations in several ways, including the following:

        Our leverage could have important consequences to investors in the notes. We will require substantial cash flow to meet our principal and interest obligations with respect to the notes and our other indebtedness. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business and other factors. We believe that we will have sufficient cash flow from operations and available borrowings under our Credit Agreement to service our indebtedness. However, a significant downturn in our business or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or a portion of our debt or sell assets. We cannot assure you that we would be able to refinance our existing indebtedness or sell assets on terms that are commercially reasonable.

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         We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

        We are a holding company, and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than our interest in our operating subsidiaries. As a result, our ability to make required payments on the notes depends on the performance of our operating subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, our Credit Agreement and the purchase agreement governing our Existing Senior Secured Notes and applicable state partnership laws and other laws and regulations. If we are unable to obtain the funds necessary to pay the principal amount at maturity of the notes, or to repurchase the notes upon the occurrence of a change of control, we may be required to adopt one or more alternatives, such as a refinancing of the notes or a sale of assets. We may not be able to refinance the notes or sell assets on acceptable terms, or at all.

         Despite our current level of indebtedness, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial indebtedness.

        We may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our Credit Agreement and under the indenture for the notes. If new debt is added to our current debt levels, the related risks that we now face could increase. Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations, including those relating to the notes.

         The notes and the guarantees are unsecured and effectively subordinated to our and our subsidiary guarantors' existing and future secured indebtedness.

        The notes and the guarantees are general unsecured senior obligations ranking effectively junior in right of payment to all existing and future secured debt of ours and that of any subsidiary guarantors, including obligations under our Credit Agreement and our Existing Senior Secured Notes, to the extent of the value of the collateral securing the debt. If we or any subsidiary guarantor is declared bankrupt, becomes insolvent or is liquidated or reorganized, any secured debt of ours or of such subsidiary guarantor will be entitled to be paid in full from our assets or the assets of such subsidiary guarantor, as applicable, securing that debt before any payment may be made with respect to the notes or the affected guarantees. Holders of the notes will participate ratably with all holders of our other unsecured indebtedness that does not rank junior to the notes, including all of our other general creditors, based upon the respective amounts owed to each holder or creditor, in our remaining assets. In any of the foregoing events, we cannot assure you that there will be sufficient assets to pay amounts due on the notes. As a result, holders of the notes would likely receive less, ratably, than holders of secured indebtedness.

         The notes and the guarantees are structurally subordinated to all liabilities of our non-guarantor subsidiaries.

        The notes are structurally subordinated to the indebtedness and other liabilities of our subsidiaries that are not guaranteeing the notes. These non-guarantor subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any amounts due pursuant to the notes, or to make any funds available therefor, whether by loans, distributions or other payments. Any right that we or the subsidiary guarantors have to receive any assets of any of the non-guarantor subsidiaries upon the liquidation or reorganization of those non-guarantor subsidiaries, and the consequent rights of

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holders of notes to realize proceeds from the sale of any of those non-guarantor subsidiaries' assets, will be effectively subordinated to the claims of those non-guarantor subsidiaries' creditors, including trade creditors and holders of preferred equity interests of those non-guarantor subsidiaries. Accordingly, in the event of a bankruptcy, liquidation or reorganization of any of our non-guarantor subsidiaries, these non-guarantor subsidiaries will pay the holders of their debts, holders of preferred equity interests and their trade creditors before they will be able to distribute any of their assets to us. As of September 30, 2014, our non-guarantor subsidiaries (as the term "Subsidiary" is defined pursuant to the indenture governing the notes) had no material indebtedness outstanding.

         Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

        Borrowings under our Credit Agreement bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our cash available for servicing our indebtedness would decrease. A 1.0% increase in interest rates on the debt outstanding under our facility as of September 30, 2014 would have cost us approximately $10.8 million in additional annual interest expense.

         We may not have the funds necessary to finance the repurchase of the notes in connection with a change of control offer required by the indenture.

        Upon the occurrence of specific kinds of change of control events, the indenture governing the notes requires us to make an offer to repurchase all such notes at 101% of the principal amount thereof, plus accrued and unpaid interest (and liquidated damages, if any) to the date of repurchase. However, it is possible that we will not have sufficient funds, or the ability to raise sufficient funds, at the time of the change of control to make the required repurchase of the notes. In addition, restrictions under our Credit Agreement and the Existing Senior Secured Notes may not allow us to make such a repurchase upon a change of control. If we could not refinance our Credit Agreement or Existing Senior Secured Notes or otherwise obtain a waiver from the holders of such debt, we would be prohibited from repurchasing the notes, which would constitute an event of default under the indenture. In addition, certain important corporate events, such as leveraged recapitalizations that would increase the level of our indebtedness, would not constitute a "Change of Control" under the indenture. Because the definition of change of control under our Credit Agreement differs from that under the indenture, there may be a change of control and resulting default under our Credit Agreement at a time when no change of control has occurred under the indenture. Please read "Description of Notes—Repurchase at the Option of Holders—Change of Control."

         Holders of the notes may not be able to determine when a change of control giving rise to their right to have the notes repurchased has occurred following a sale of "substantially all" of our assets.

        The definition of change of control in the indenture governing the notes includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of "all or substantially all" of the properties or assets of the Partnership and its subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require us to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of the Partnership and its subsidiaries taken as a whole to another person or group may be uncertain.

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         Federal and state statutes allow courts, under specific circumstances, to void guarantees and require noteholders to return payments received from subsidiary guarantors.

        Under the federal bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee of the notes could be voided, or claims in respect of a guarantee could be subordinated to all other debts of that subsidiary guarantor, if, among other things, the subsidiary guarantor, at the time it incurred the debt evidenced by its guarantee:

        In addition, any payment by that subsidiary guarantor pursuant to its guarantee could be voided and required to be returned to the subsidiary guarantor, or to a fund for the benefit of our creditors or the creditors of the guarantor.

        The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a subsidiary guarantor would be considered insolvent if:

        On the basis of historical financial information, recent operating history and other factors, we believe that each subsidiary guarantor, after giving effect to its guarantee of the notes, will not be insolvent, will not have unreasonably small capital for the business in which it is engaged and will not have incurred debts beyond its ability to pay such debts as they mature. We cannot assure you, however, as to what standard a court would apply in making these determinations or that a court would agree with our conclusions in this regard.

         If an active trading market does not develop for the new notes you may not be able to resell them.

        Prior to this offering, there was no trading market for the new notes, and we cannot assure you that an active trading market will develop. If no active trading market develops, you may not be able to resell your notes at their fair market value or at all. Future trading prices of the notes will depend on many factors, including, among other things, our ability to consummate this exchange offer, prevailing interest rates, our operating results and the market for similar securities. We do not intend to apply to list the notes on any securities exchange.

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         Many of the covenants contained in the indenture will terminate if the notes are rated investment grade by any two of Standard & Poor's Ratings Services, Moody's Investor Service, Inc. and Fitch Ratings, Inc. and no default has occurred and is continuing.

        Many of the covenants in the indenture governing the notes will terminate if the notes are rated investment grade by any two of Standard & Poor's, Moody's, and Fitch provided that at such time no default has occurred and is continuing. The covenants restrict, among other things, our ability to pay distributions, incur debt and to enter into certain other transactions. There can be no assurance that the notes will ever be rated investment grade. However, termination of these covenants would allow us to engage in certain transactions that would not have been permitted while these covenants were in force, and the effects of any such transactions will be permitted to remain in place even if the notes are subsequently downgraded below investment grade. See "Description of Notes—Certain Covenants—Covenant Termination."

         The tax treatment of publicly traded partnerships could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

        The present U.S. federal income tax treatment of publicly traded partnerships, including us, may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. We are unable to predict whether any such proposals will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could cause a material reduction in our anticipated cash flow, which could materially and adversely affect our ability to make payments on the notes and our other debt obligations and could cause a reduction in the value of the notes.

Risks Related to our Business

         Our future financial performance and growth may be limited by our ability to successfully complete accretive acquisitions on economically acceptable terms.

        Our ability to consummate acquisitions on economically acceptable terms may be limited by various factors, including, but not limited to:

        There can be no assurance that we will identify attractive acquisition candidates in the future, that we will be able to acquire such businesses on economically acceptable terms, that any acquisitions will not be dilutive to earnings and distributions or that any additional debt that we incur to finance an acquisition will not affect our ability to service our debt obligations, including the notes. Furthermore, if we consummate any future acquisitions, our capitalization and results of operations may change

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significantly, and investors will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

        The propane industry is a mature industry. We anticipate only limited growth in total national demand for propane in the near future. Increased competition from alternative energy sources has limited growth in the propane industry, and year-to-year industry volumes are primarily impacted by fluctuations in weather and economic conditions. In addition, our retail propane business concentrates on sales to residential customers, but because of longstanding customer relationships that are typical in the retail residential propane industry, the inconvenience of switching tanks and suppliers, we may have difficulty in increasing our retail customer base other than through acquisitions. Therefore, while our business strategy includes expanding our existing retail propane operations through internal growth, our ability to grow within the retail propane business will depend principally on acquisitions.

         We may be subject to substantial risks in connection with the integration and operation of acquired businesses, in particular those businesses with operations that are distinct and separate from our existing operations.

        Any acquisitions we make in pursuit of our growth strategy are subject to potential risks, including, but not limited to:

        We undertake due diligence efforts in our assessment of acquisitions, but may be unable to identify or fully plan for all issues and risks attendant to a particular acquisition. Even when an issue or risk is identified, we may be unable to obtain adequate contractual protection from the seller. The realization of any of these risks could have a material adverse effect on the success of a particular acquisition or our financial condition, results of operations or future growth.

        As part of our growth strategy, we may expand our operations into businesses that differ from our existing operations. Integration of new businesses is a complex, costly and time-consuming process and may involve assets with which we have limited operating experience. Failure to timely and successfully integrate acquired businesses into our existing operations may have a material adverse effect on our business, financial condition or results of operations. In addition to the risks set forth above, new businesses will subject us to additional business and operating risks, increased interest expense related to debt we incur to make such acquisitions or an inability to successfully integrate those operations into our overall business operation. The realization of any of these risks could have a material adverse effect on our financial condition or results of operations.

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         Debt we have incurred or will incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

        Our level of debt could have important consequences to us, including the following:

        Our ability to service our debt will depend on, among other things, our future financial and operating performance, which will be affected by prevailing economic and weather conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our future indebtedness, we would be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may be unable to effect any of these actions on satisfactory terms or at all. The agreements governing our indebtedness permit us to incur additional debt under certain circumstances, and we will likely need to incur additional debt in order to implement our growth strategy. We may experience adverse consequences from increased levels of debt.

         Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.

        Interest rates may increase in the future. As a result, interest rates on our existing and future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price will be impacted by our level of cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make payments on our debt obligations and cash distributions at our intended levels.

         Our business depends on the availability of supply of crude oil and natural gas liquids in the United States and Canada, which is dependent on the ability and willingness of other parties to explore for and produce crude oil and natural gas. Spending on crude oil and natural gas exploration and production may be adversely affected by industry and financial market conditions that are beyond our control including, without limitation, (1) prices for crude oil, condensate, and natural gas liquids, (2) crude oil and natural gas producers having success in their operations, (3) continued commercially viable areas in which to explore and produce crude oil and natural gas, (4) the availability of liquids-rich natural gas needed to produce natural gas liquids, and (5) the availability of pipeline transportation and storage capacity.

        Our business depends on domestic spending by the oil and natural gas industry, and this spending and our business have been, and may continue to be, adversely affected by industry and financial market conditions and existing or new regulations, such as those related to environmental matters, that are beyond our control.

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        We depend on the ability and willingness of other entities to make operating and capital expenditures to explore for, develop, and produce oil and natural gas in the United States and Canada, and to extract natural gas liquids from natural gas as well as the availability of necessary pipeline transportation and storage capacity. Customers' expectations of lower market prices for oil and natural gas, as well as the availability of capital for operating and capital expenditures, may cause them to curtail spending, thereby reducing business opportunities and demand for our services and equipment. Actual market conditions and producers' expectations of market conditions for crude oil, condensate and natural gas liquids may also cause producers to curtail spending, thereby reducing business opportunities and demand for our services.

        Industry conditions are influenced by numerous factors over which we have no control, such as the availability of commercially viable geographic areas in which to explore and produce oil and natural gas, the availability of liquids-rich natural gas needed to produce natural gas liquids, the supply of and demand for oil and natural gas, environmental restrictions on the exploration and production of oil and natural gas, such as existing and proposed regulation of hydraulic fracturing, domestic and worldwide economic conditions, political instability in oil and natural gas producing countries and merger and divestiture activity among our current or potential customers. The volatility of the oil and natural gas industry and the resulting impact on exploration and production activity could adversely impact the level of drilling activity. This reduction may cause a decline in business opportunities or the demand for our services, or adversely affect the price of our services. Reduced discovery rates of new oil and natural gas reserves in our market areas also may have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices, to the extent existing production is not replaced.

        The oil and natural gas production industry tends to run in cycles and may, at any time, cycle into a downturn; if that occurs again, the rate at which it returns to former levels, if ever, will be uncertain. Prior adverse changes in the global economic environment and capital markets and declines in prices for oil and natural gas have caused many customers to reduce capital budgets for future periods and have caused decreased demand for oil and natural gas. Limitations on the availability of capital, or higher costs of capital, for financing expenditures have caused and may continue to cause customers to make additional reductions to capital budgets in the future even if commodity prices increase from current levels. These cuts in spending may curtail drilling programs and other discretionary spending, which could result in a reduction in business opportunities and demand for our services, the rates we can charge and our utilization. In addition, certain of our customers could become unable to pay their suppliers, including us. Any of these conditions or events could materially and adversely affect our operating results.

         Our profitability could be negatively impacted by price and inventory risk related to our business.

        The crude oil logistics, liquids, retail propane, refined products, and renewables businesses are "margin-based" businesses in which our realized margins depend on the differential of sales prices over our total supply costs. Our profitability is therefore sensitive to changes in product prices caused by changes in supply, pipeline transportation and storage capacity or other market conditions.

        Generally, we attempt to maintain an inventory position that is substantially balanced between our purchases and sales, including our future delivery obligations. We attempt to obtain a certain margin for our purchases by selling our product to our customers, which include third-party consumers, other wholesalers and retailers, and others. However, market, weather or other conditions beyond our control may disrupt our expected supply of product, and we may be required to obtain supply at increased prices that cannot be passed through to our customers. In general, product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major storage points, creating the potential for sudden and drastic price fluctuations. Sudden and extended wholesale price increases could reduce our margins and could, if continued over an extended period of

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time, reduce demand by encouraging retail customers to conserve or convert to alternative energy sources. Conversely, a prolonged decline in product prices could potentially result in a reduction of the borrowing base under our working capital facility, and we could be required to liquidate inventory that we have already pre-sold.

         We are affected by competition from other midstream, transportation, terminaling and storage and retail marketing companies, some of which are larger and more firmly established and may have greater marketing and development budgets and capital resources than we do.

        We experience competition in all of our segments. In our liquids segment, we compete for natural gas supplies and also for customers for our services. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas. Our natural gas liquids terminals compete with other terminaling and storage providers in the transportation and storage of natural gas liquids. Natural gas and natural gas liquids also compete with other forms of energy, including electricity, coal, fuel oil and renewable or alternative energy.

        Our crude oil logistics segment faces significant competition for crude oil supplies and also for customers for our services. These operations also face competition from trucks for incremental and marginal volumes in the areas we serve. Further, our crude oil terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

        Our water solutions segment is in direct and indirect competition with other businesses, including disposal and other wastewater treatment businesses.

        We face strong competition in the market for the sale of retail propane. Our competitors vary from retail propane companies who are larger and have substantially greater financial resources than we do to small retail propane distributors, rural electric cooperatives and fuel oil distributors who have entered the market due to a low barrier to entry. The actions of our retail marketing competitors, including the impact of imports, could lead to lower prices or reduced margins for the products we sell, which could have an adverse effect on our business or results of operations.

        Our refined products and renewables segments also face significant competition for refined products and renewables supplies and also for customers for our services.

        We can make no assurances that we will be able to compete successfully in each of our lines of business. If a competitor attempts to increase market share by reducing prices, we may lose customers, which would reduce our revenues.

         Our business would be adversely affected if service at our principal storage facilities or on the common carrier pipelines we use is interrupted.

        We use third-party common carrier pipelines to transport crude oil and natural gas liquids and we use third-party facilities to store natural gas liquids and ethanol. Any significant interruption in the service at these storage facilities or on the common carrier pipelines we use would adversely affect our ability to obtain propane.

         Our business would be adversely affected if service on the railroads we use is interrupted.

        We transport crude oil, natural gas liquids, ethanol, and biodiesel by railcar. We do not own or operate the railroads on which these cars are transported. Any disruptions in the operations of these railroads could adversely impact our ability to deliver product to our customers.

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         If we are unable to purchase product from our principal suppliers, our results of operations would be adversely affected.

        If we are unable to purchase product from significant suppliers, our failure to obtain alternate sources of supply at competitive prices and on a timely basis would adversely affect our ability to satisfy customer demand, reduce our revenues and adversely affect our results of operations.

         The fees charged to customers under our agreements with them for the transportation and marketing of crude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel may not escalate sufficiently to cover increases in costs and the agreements may be suspended in some circumstances, which would affect our profitability.

        Our costs may increase at a rate greater than the rate that the fees that we charge to customers increase pursuant to our contracts with them. Additionally, some customers' obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of crude oil, condensate, and/or natural gas liquids are curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of our equipment or facilities of our customers. If the escalation of fees is insufficient to cover increased costs or if any customer suspends or terminates its contracts with us, our profitability could be materially and adversely affected.

         Our sales of crude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel and related transportation and hedging activities, and our processing of wastewater, expose us to potential regulatory risks.

        The Federal Trade Commission ("FTC"), the Federal Energy Regulatory Commission ("FERC"), and the Commodity Futures Trading Commission ("CFTC") hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of energy commodities, and any related transportation and/or hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales may also be subject to certain reporting and other requirements. Additionally, to the extent that we enter into transportation contracts with pipelines that are subject to the FERC regulation or we become subject to the FERC regulation ourselves (see—"Some of our operations could become subject to the jurisdiction of the FERC," below), we will be obligated to comply with the FERC's regulations and policies. Any failure on our part to comply with the FERC's regulations and policies at that time could result in the imposition of civil and criminal penalties. Failure to comply with such regulations, as interpreted and enforced, could have a material and adverse effect on our business, results of operations and financial condition.

        The intrastate transportation or storage of natural gas or crude oil is subject to regulation by the state in which the facilities and transactions occur and requires compliance with all such regulation. This state regulation can have a material and adverse effect on that portion of our business, results of operations and financial condition.

        The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") provides for statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Certain transactions will be required to be cleared on exchanges and cash collateral will have to be posted. The Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end users and it includes a number of defined terms that will be used in determining how this exemption applies to particular derivative transactions

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and the parties to those transactions. Since the Dodd-Frank Act mandates the CFTC to promulgate rules to define these terms, we do not know the definitions the CFTC will actually adopt or how these definitions will apply to us. Although the CFTC established position limits on certain core futures and equivalent swaps contracts, with exceptions for certain bona fide hedging transactions, those limits were vacated by a federal district court on September 28, 2012, and will not go into effect until the CFTC prevails on appeal of this ruling, or issues and finalizes revised rules. Additionally, in December 2012, the CFTC published final rules regarding mandatory clearing of four classes of interest rate swaps and two classes of credit swaps and setting compliance dates of March 11, 2013, June 10, 2013, and, for end users of swaps, September 9, 2013. The full impact of the Dodd-Frank Act on our hedging activities is uncertain at this time. However, new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. The Dodd-Frank Act may also materially affect our customers and materially and adversely affect the demand for our services.

         We are subject to the trucking safety regulations, which are likely to be amended, and made stricter, as part of the initiative known as Comprehensive, Safety, Analysis ("CSA"). If our current United States Department of Transportation ("DOT") safety ratings are downgraded to "Unsatisfactory" or the equivalent in connection with this initiative, our business and results of our operations may be adversely affected.

        As part of the CSA initiative, the Federal Motor Carrier Safety Administration ("FMCSA") is expected to open a rulemaking docket for purposes of changing its safety rating methodology. Any new methodology adopted in the rulemaking is likely to link safety ratings more closely to roadside inspection and driver violation data gathered and analyzed from month to month under the agency's new Safety Measurement System ("SMS"). This linkage could result in greater variability in safety ratings than the current system, in which a safety rating is based on relatively infrequent on-site compliance audits at a carrier's place(s) of business. Preliminary studies by transportation consulting firms indicate that "Satisfactory" ratings (or any equivalent under a new SMS-based system) may become more difficult to achieve and maintain under such a system. If we ever receive an "Unsatisfactory" or equivalent rating, we may lose some of our customer contracts that require such a rating, which may materially and adversely affect our business prospects and results of operations.

         Our business is subject to federal, state, provincial and local laws and regulations with respect to environmental, safety and other regulatory matters and the cost of compliance with, violation of or liabilities under, such laws and regulations could adversely affect our profitability.

        Our operations, including those involving crude oil, condensate, natural gas liquids, and oil and gas produced wastewater, are subject to stringent federal, state, provincial and local laws and regulations relating to the protection of natural resources and the environment, health and safety, waste management, and transportation and disposal of such products and materials. We face inherent risks of incurring significant environmental costs and liabilities in the performance of our operations due to handling of wastewater and hydrocarbons, such as crude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel. For instance, our wastewater treatment and transportation business carries with it environmental risks, including leakage from the treatment plants to surface or subsurface soils, surface water or groundwater, or accidental spills or releases during the transport of wastewater. Our crude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel businesses carry similar risks of leakage and sudden or accidental spills of crude oil, condensate, natural gas liquids, and hydrocarbons. Liability under, or violation of, environmental laws and regulations could result in, among other things, the impairment or cancellation of operations, injunctions, fines and penalties,

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reputational damage, expenditures for remediation and liability for natural resource damages, property damage and personal injuries.

        We use various modes of transportation to carry propane, distillates, crude oil and water, including trucks, railcars and barges, each of which is subject to regulation. With respect to transportation by truck, we are subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002, which cover the security and transportation of hazardous materials and are administered by the DOT. We also own and lease a fleet of railcars, the operation of which is subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, as well as other federal and state regulatory agencies. In response to recent train derailments occurring in the United States and Canada in 2013, United States regulators are implementing or considering new rules to address the safety risks of transporting crude oil by rail. On January 23, 2014, the National Transportation Safety Board issued a series of recommendations to address safety risks, and on February 25, 2014 the DOT issued an emergency order requiring all persons, prior to offering petroleum crude oil into transportation, to ensure such product is properly tested and classed. The introduction of these or other regulations that result in new requirements addressing the type, design, specifications or construction of railcars used to transport crude oil could result in severe transportation capacity constraints during the period in which new railcars are retrofitted or constructed to meet new specifications. Our barge transportation operations, which we acquired in 2012, are subject to the Jones Act, a federal law restricting marine transportation in the United States to vessels built and registered in the United States, and manned and owned by United States citizens, as well as rules and regulations of the United States Coast Guard. Non-compliance with any of these regulations could result in increased costs related to the transportation of our products and could have an adverse effect on our business.

        In addition, under certain environmental laws, we could be subject to strict and/or joint and several liability for the investigation, removal or remediation of previously released materials. As a result, these laws could cause us to become liable for the conduct of others, such as prior owners or operators of our facilities, or for consequences of our or our predecessor's actions, regardless of whether we were responsible for the release or if such actions were in compliance with all applicable laws at the time of those actions. Also, upon closure of certain facilities, such as at the end of their useful life, we have been and may be required to undertake environmental evaluations or cleanups.

        Additionally, in order to conduct our operations, we must obtain and maintain numerous permits, approvals and other authorizations from various federal, state, provincial and local governmental authorities relating to wastewater handling, discharge and disposal, air emissions, transportation and other environmental matters. These authorizations subject us to terms and conditions which may be onerous or costly to comply with, and that may require costly operational modifications to attain and maintain compliance. The renewal, amendment or modification of these permits, approvals and other authorizations may involve the imposition of even more stringent and burdensome terms and conditions with attendant higher costs and more significant effects upon our operations.

        Changes in environmental laws and regulations occur frequently. New laws or regulations, changes to existing laws or regulations, such as more stringent pollution control requirements or additional safety requirements, or more stringent interpretation or enforcement of existing laws and regulations, may unfavorably impact us, and could result in increased operating costs and have a material and adverse effect on our activities and profitability. For example, new or proposed laws or regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our costs for treatment of frac flow-back water (or affect our hydraulic fracturing customers' ability to operate) and cause delays, interruption or termination of our water treatment operations, all of which could have a material and adverse effect on our operations and financial performance.

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        Furthermore, our customers in the oil and gas production industry are subject to certain environmental laws and regulations that may impose significant costs and liabilities on them, including as a result of changes in such laws and regulations causing them to become more stringent over time. For example, in April 2012, the EPA issued final rules that established new air emission controls for oil and gas production and gas processing operations. The final rule includes a 95% reduction in volatile organic compounds ("VOCs") (which contribute to smog) emitted during the completion of new and modified hydraulically fractured wells. In August 2013, the EPA updated its 2012 air emission standards for crude oil and natural gas storage tanks to extend the compliance date and allow an alternate emissions limit of less than 4 tons per year without emission controls. Any significant increased costs or restrictions placed on our customers to comply with environmental laws and regulations could affect their production output significantly. Such an effect could materially and adversely affect our utilization and profitability, thus reducing demand for our midstream services. Such an effect on our customers could materially and adversely affect our utilization and profitability. The adoption or implementation of any new regulations imposing additional reporting obligations on greenhouse gas emissions, or limiting greenhouse gas emissions from our equipment and operations, could require us to incur significant costs.

         Federal and state legislation and regulatory initiatives relating to our hydraulic fracturing customers could result in increased costs and additional operating restrictions or delays and could harm our business.

        Hydraulic fracturing is a frequent practice in the oil and gas fields in which our water solutions segment operates. Hydraulic fracturing is an important and common process used to facilitate production of natural gas and other hydrocarbon condensates in shale formations, as well as tight conventional formations. The hydraulic fracturing process is typically regulated by state oil and gas authorities. This process has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that chemicals used in the fracturing process could adversely affect drinking water supplies. In addition, some have asserted that the fracturing process and/or the wastewater disposal process could result in increased seismic activity. New laws or regulations, or changes to existing laws or regulations in response to this perceived threat may unfavorably impact the oil and gas drilling industry. For instance, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices involving the use of diesel fuel under the Safe Drinking Water Act and its Underground Injection Control program. In February 2014, the EPA issued technical guidance for the permitting of the underground injection of diesel fuel for hydraulic fracturing activities. The EPA has also commenced a study of the potential environmental impact of hydraulic fracturing activities, the final results of which are expected in 2014. In addition, the United States Department of the Interior published a revised proposed rule on May 16, 2013 that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. Also, legislation has been introduced, but not adopted, in Congress to provide for federal regulation of hydraulic fracturing. In addition, some states have adopted and other states are considering adopting regulations that could restrict or regulate hydraulic fracturing in certain circumstances. For example, some states have adopted legislation requiring the disclosure of hydraulic fracturing chemicals, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. We cannot predict whether any proposed federal, state or local laws or regulations will be enacted and, if so, what actions any such laws or regulations would require or prohibit. However, any restrictions on hydraulic fracturing could lead to operational delays or increased operating costs and regulatory burdens that could make it more difficult or costly to perform hydraulic fracturing which would negatively impact our customer base resulting in an adverse effect on our profitability.

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         Seasonal weather conditions and natural or man-made disasters could severely disrupt normal operations and have an adverse effect on our business, financial condition and results of operations.

        We operate in various locations across the United States and Canada which may be adversely affected by seasonal weather conditions and natural or man-made disasters. During periods of heavy snow, ice, rain or extreme weather conditions such as high winds, tornados and hurricanes or after other natural disasters such as earthquakes or wildfires, we may be unable to move our trucks or railcars between locations and our facilities may be damaged, thereby reducing our ability to provide services and generate revenues. In addition, hurricanes or other severe weather in the Gulf Coast region could seriously disrupt the supply of products and cause serious shortages in various areas, including the areas in which we operate. These same conditions may cause serious damage or destruction to homes, business structures and the operations of customers. Such disruptions could potentially have a material adverse impact on our business, financial condition, results of operations and cash flows.

         Risk management procedures cannot eliminate all commodity risk, basis risk, or risk of adverse market conditions which can adversely affect our financial condition and results of operations. In addition, any non-compliance with our risk policy could result in significant financial losses.

        Pursuant to the requirements of our market risk policy, we attempt to lock in a margin for a portion of the commodities we purchase by selling such commodities for physical delivery to our customers, such as independent refiners or major oil companies, or by entering into future delivery obligations under contracts for forward sale. Through these transactions, we seek to maintain a position that is substantially balanced between purchases on the one hand, and sales or future delivery obligations on the other hand. These policies and practices cannot, however, eliminate all risks. For example, any event that disrupts our anticipated physical supply of commodities could expose us to risk of loss resulting from the need to cover obligations required under contracts for forward sale. Additionally, we can provide no assurance that our processes and procedures will detect and/or prevent all violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

        Basis risk describes the inherent market price risk created when a commodity of certain grade or location is purchased, sold or exchanged as compared to a purchase, sale or exchange of a like commodity at a different time or place. Transportation costs and timing differentials are components of basis risk. In a backwardated market (when prices for future deliveries are lower than current prices), basis risk is created with respect to timing. In these instances, physical inventory generally loses value as price of such physical inventory declines over time. Basis risk cannot be entirely eliminated, and basis exposure, particularly in backwardated or other adverse market conditions, can adversely affect our financial condition and results of operations.

         The counterparties to our commodity derivative and physical purchase and sale contracts may not be able to perform their obligations to us, which could materially affect our cash flows and results of operations.

        We encounter risk of counterparty non-performance in our businesses. Disruptions in the supply of product and in the oil and gas commodities sector overall for an extended or near term period of time could result in counterparty defaults on our derivative and physical purchase and sale contracts. This could impair our ability to obtain supply to fulfill our sales delivery commitments or obtain supply at reasonable prices, which could result in decreased gross margins and profitability, thereby impairing our ability to service our debt obligations, including the notes.

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         Our use of derivative financial instruments could have an adverse effect on our results of operations.

        We have used derivative financial instruments as a means to protect against commodity price risk or interest rate risk and expect to continue to do so. We may, as a component of our overall business strategy, increase or decrease from time to time our use of such derivative financial instruments in the future. Our use of such derivative financial instruments could cause us to forego the economic benefits we would otherwise realize if commodity prices or interest rates were to change in our favor. In addition, although we monitor such activities in our risk management processes and procedures, such activities could result in losses, which could adversely affect our results of operations and impair our ability to make payments on our debt obligations.

         Some of our operations could become subject to the jurisdiction of the FERC.

        Any of our transportation services could in the future become subject to the jurisdiction of the FERC, which could adversely affect the terms of service, rates and revenues of such services. As of March 31, 2014, our facilities do not fall under the FERC's jurisdiction. Currently, the FERC regulates crude oil and natural gas pipelines, among other things. Intrastate transportation and gathering pipelines that do not provide interstate services are not subject to regulation by the FERC. However, the distinction between the FERC-regulated interstate pipeline transportation on the one hand and intrastate pipeline transportation on the other hand, is a fact-based determination. The classification and regulation of our crude oil pipelines are subject to change based on future determinations by the FERC, federal courts, Congress or regulatory commissions, courts or legislatures in the states in which we operate. Glass Mountain Pipeline, LLC ("Glass Mountain"), one of our joint ventures, owns a pipeline in Oklahoma that carries crude oil owned by us and by third parties. We believe that the pipeline segments on which Glass Mountain would provide service to third parties and the services it would provide to third parties on this pipeline system meet the traditional tests that the FERC has used to determine that the pipeline services provided are not in interstate commerce. However, we cannot provide assurance that the FERC will not in the future, either at the request of other entities or on its own initiative, determine that some or all of the pipeline and the services Glass Mountain will provide on that system are within its jurisdiction, or that such a determination would not adversely affect Glass Mountain's or our results of operations. Further, if the FERC's regulatory reach was expanded to our other facilities, or if we expand our operations into areas that are subject to the FERC's regulation, we may have to commit substantial capital to comply with such regulations and such expenditures could have a material and adverse effect on our results of operations and cash flows.

         Volumes of crude oil recovered during the wastewater treatment process can vary. Any significant reduction in residual crude oil content in wastewater we treat will affect our recovery of crude oil and, therefore, our profitability.

        A significant portion of revenues in our water business is derived from sales of crude oil recovered during the wastewater treatment process. Our ability to recover sufficient volumes of crude oil is dependent upon the residual crude oil content in the wastewater we treat, which is, among other things, a function of water temperature. Generally, where water temperature is higher, residual crude oil content is lower. Thus, our crude oil recovery during the winter season is substantially higher than our recovery during the summer season. Additionally, residual crude oil content will decrease if, among other things, producers begin recovering higher levels of crude oil in produced wastewater prior to delivering such water to us for treatment. Any reduction in residual crude oil content in the wastewater we treat could materially and adversely affect our profitability.

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         Competition from alternative energy sources may cause us to lose customers, thereby negatively impacting our financial condition and results of operations.

        Propane competes with other sources of energy, some of which are less costly for equivalent energy value. We compete for customers against suppliers of electricity, natural gas and fuel oil. Competition from alternative energy sources, including electricity and natural gas, has increased as a result of reduced regulation of many utilities. Electricity is a major competitor of propane, but propane has historically enjoyed a competitive price advantage over electricity. Except for some industrial and commercial applications, propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because such pipelines generally make it possible for the delivered cost of natural gas to be less expensive than the bulk delivery of propane. The expansion of natural gas into traditional propane markets has historically been inhibited by the capital cost required to expand distribution and pipeline systems; however, the gradual expansion of the nation's natural gas distribution systems has resulted in natural gas being available in areas that previously depended on propane, which could cause us to lose customers, thereby reducing our revenues. Although propane is similar to fuel oil in some applications and market demand, propane and fuel oil compete to a lesser extent primarily because of the cost of converting from one to the other and due to the fact that both fuel oil and propane have generally developed their own distinct geographic markets.

        We cannot predict the effect that development of alternative energy sources may have on our operations, including whether subsidies of alternative energy sources by local, state, and federal governments might be expanded, or what impact this might have on the supply of or the demand for crude oil, natural gas, and natural gas liquids.

         Energy efficiency and new technology may reduce the demand for propane and adversely affect our operating results.

        The national trend toward increased conservation and technological advances, such as installation of improved insulation and the development of more efficient furnaces and other heating devices, has adversely affected the demand for propane by retail customers. Future conservation measures or technological advances in heating, conservation, energy generation or other devices may reduce demand for propane. In addition, if the price of propane increases, some of our customers may increase their conservation efforts and thereby decrease their consumption of propane.

         The majority of our retail propane operations are concentrated in the Northeast, Southeast, and Midwest, and localized warmer weather and/or economic downturns may adversely affect demand for propane in those regions, thereby affecting our financial condition and results of operations.

        A substantial portion of our retail propane sales are to residential customers located in the Northeast, Southeast, and Midwest who rely heavily on propane for heating purposes. A significant percentage of our retail propane volume is attributable to sales during the peak heating season of October through March. Warmer weather may result in reduced sales volumes that could adversely impact our operating results and financial condition. In addition, adverse economic conditions in areas where our retail propane operations are concentrated may cause our residential customers to reduce their use of propane regardless of weather conditions. Localized warmer weather and/or economic downturns may have a significantly greater impact on our operating results and financial condition than if our retail propane business were less concentrated.

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         Reduced demand for refined products could have an adverse effect our results of operations.

        Any sustained decrease in demand for refined products in the markets we serve could reduce our cash flow. Factors that could lead to a decrease in market demand include:

         Recent attempts to reduce or eliminate the Renewable Fuels Standard, if successful, could unfavorably impact our results of operations.

        The United States renewables industry is highly dependent on several federal and state incentives which promote the use of renewable fuels. Without these incentives, demand for and the price of renewable fuels could be negatively impacted which could have an adverse effect on our results of operations. The most significant of the federal and state incentives which benefit renewable products we market, such as ethanol and biodiesel, is the federal Renewable Fuels Standard ("RFS"). The RFS requires that an increasing amount of renewable fuels must be blended with petroleum-based fuels each year in the United States. However, the EPA has authority to waive the requirements of the RFS, in whole or in part, provided one of two conditions is met. The conditions are: (1) there is inadequate domestic renewable fuel supply; or (2) implementation of the requirement would severely harm the economy or environment of a state, region or the United States. Opponents of the RFS are seeking to force the EPA to reduce or eliminate the RFS. Further, several pieces of legislation have been introduced with the goal of significantly reducing or eliminating the RFS. While the outcome of these legislative efforts is uncertain, it is possible that the EPA could adjust the RFS requirements in the future. If the EPA were to adjust the RFS requirements in any material way, it could negatively impact demand for the renewable fuel products we market, which could unfavorably impact our results of operations.

         A loss of one or more significant customers could materially or adversely affect our results of operations.

        Approximately 37% of the revenues of our water solutions segment during the year ended March 31, 2014 were generated from our two largest customers of the segment. Approximately 60% of the revenues of our crude oil logistics segment during the year ended March 31, 2014 were generated from our ten largest customers of the segment. Approximately 35% of the revenues of our liquids segment were generated from our ten largest customers of the segment. Approximately 41% of the revenues of our refined products segment were generated from our ten largest customers of the segment. Approximately 70% of the revenues of our renewables segment were generated from our ten largest customers of the segment. For the year ended March 31, 2014, sales of crude oil and natural gas liquids to our largest customer represented 10% of our consolidated total revenues. We expect to continue to depend on key customers to support our revenues for the foreseeable future. The loss of key customers, failure to renew contracts upon expiration, or a sustained decrease in demand by key customers could result in a substantial loss of revenues and could have a material and adverse effect on our results of operations.

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         Certain of our operations are conducted through joint ventures which have unique risks.

        Certain of our operations are conducted through joint ventures. With respect to our joint ventures, we share ownership and management responsibilities with partners that may not share our goals and objectives. Differences in views among the partners may result in delayed decisions or failures to agree on major matters, such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, among others. Delay or failure to agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the joint venture. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business and operations. From time to time, our joint ventures may be involved in disputes or legal proceedings which may negatively affect our investments. Accordingly, any such occurrences could adversely affect our financial condition, operating results and cash flows.

         Growing our business by constructing new transportation systems and facilities subjects us to construction risks and risks that supplies for such systems and facilities will not be available upon completion thereof.

        One of the ways we intend to grow our business is through the construction of additions to our systems and/or the construction of new terminaling, transportation, and wastewater treatment facilities. The construction of such facilities requires the expenditure of significant amounts of capital, which may exceed our resources, and involves numerous regulatory, environmental, political and legal uncertainties. If we undertake these projects, we may not be able to complete them on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase upon the expenditure of funds on a particular project. For instance, if we build a new wastewater treatment facility, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until at least after completion of the project, if at all. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize or for which we are unable to acquire new customers. We may also rely on estimates of proved, probable or possible reserves in our decision to build new transportation systems and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved, probable or possible reserves. As a result, new facilities may not be able to attract enough product to achieve our expected investment return, which could materially and adversely affect our results of operations and financial condition.

         Product liability claims and litigation could adversely affect our business and results of operations.

        Our operations are subject to all operating hazards and risks incident to handling, storing, transporting and providing customers with combustible liquids. As a result, we are subject to product liability claims and lawsuits, including potential class actions, in the ordinary course of business. Any product liability claim brought against us, with or without merit, could be costly to defend and could result in an increase of our insurance premiums. Some claims brought against us might not be covered by our insurance policies. In addition, we have self-insured retention amounts which we would have to pay in full before obtaining any insurance proceeds to satisfy a judgment or settlement and we may have insufficient reserves on our balance sheet to satisfy such self-retention obligations. Furthermore, even where the claim is covered by our insurance, our insurance coverage might be inadequate and we would have to pay the amount of any settlement or judgment that is in excess of our policy limits. We may not be able to obtain insurance on terms acceptable to us or at all since insurance varies in cost and can be difficult to obtain. Our failure to maintain adequate insurance coverage or successfully defend against product liability claims could materially and adversely affect our business, results of operations, financial condition and cash flows.

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         A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may affect adversely our financial results.

        Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk related to operational system flaws, and employee tampering or manipulation of those systems will result in losses that are difficult to detect.

        Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our business. We use computer programs to help run our financial and operations sectors, and this may subject our business to increased risks. Any future cyber security attacks that affect our facilities, our customers and any financial data could have a material adverse effect on our business. In addition, cyber-attacks on our customer and employee data may result in a financial loss, including potential fines for failure to safeguard data, and may negatively impact our reputation. Third-party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.

         We do not own all of the land on which our facilities are located, and instead lease certain facilities and equipment, and we, therefore, are subject to the possibility of increased costs to retain necessary land and equipment use which could disrupt our operations.

        We do not own all of the land on which our facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if our facilities are not properly located within the boundaries of such rights-of-way. Additionally, our loss of rights, through our inability to renew right-of-way contracts or otherwise, could materially and adversely affect our business, results of operations and financial condition.

        Additionally, certain facilities and equipment (or parts thereof) used by us are leased from third parties for specific periods, including many of our railcars. Our inability to renew facility or equipment leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material and adverse effect on our results of operations and cash flows.

        We also must operate within the terms and conditions of permits and various rules and regulations from the United States Bureau of Land Management for the rights of way on which our pipelines are constructed and the Wyoming State Engineer's Office for water well, disposal well and containment pits.

         Difficulty in attracting and retaining qualified drivers could adversely affect our growth and profitability.

        Maintaining a staff of qualified truck drivers is critical to the success of our operations. We have in the past experienced difficulty in attracting and retaining sufficient numbers of qualified drivers. In addition, due in part to current economic conditions, including the cost of fuel, insurance, and tractors and the DOT regulatory requirements, the available pool of qualified truck drivers has been declining. Regulatory requirements, including the FMCSA's CSA initiative, and an improvement in the economy could reduce the number of eligible drivers or require us to pay more to attract and retain drivers. A shortage of qualified drivers and intense competition for drivers from other companies will create difficulties in increasing the number of our drivers for our anticipated expansion in our fleet of trucks.

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If we are unable to continue to attract and retain a sufficient number of qualified drivers, we could have difficulty meeting customer demands, any of which could materially and adversely affect our growth and profitability.

         If we fail to maintain an effective system of internal controls, including internal controls over financial reporting, we may be unable to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

        We are subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). We are also subject to the obligation under Section 404(a) of the Sarbanes Oxley Act of 2002 to annually review and report on our internal control over financial reporting, and to the obligation under Section 404(b) of the Sarbanes Oxley Act to engage our independent registered public accounting firm to attest to the effectiveness of our internal controls over financial reporting.

        Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and operate successfully as a publicly traded partnership. Our efforts to maintain our internal controls may be unsuccessful, and we may be unable to maintain effective controls over financial reporting, including our disclosure controls. Any failure to maintain effective internal controls over financial reporting and disclosure controls could harm our operating results or cause us to fail to meet our reporting obligations. These risks may be heightened after a business combination, during the phase when we are implementing our internal control structure over the recently-acquired business.

        Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm's, conclusions about the effectiveness of internal controls in the future, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls could subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

         An impairment of goodwill and intangible assets could reduce our earnings.

        At March 31, 2014 and September 30, 2014, we had reported goodwill and intangible assets of approximately $1.8 billion and $2.0 billion, respectively. Such assets are subject to impairment reviews on an annual basis, or at an interim date if information indicates that such asset values have been impaired. Any impairment we would be required to record in our financial statements would result in a charge to our income, which would reduce our earnings.

         Our business requires extensive credit risk management that may not be adequate to protect against customer non-payment.

        Our credit management procedures may not fully eliminate the risk of non-payment by our customers. We manage our credit risk exposure through credit analysis, credit approvals, establishing credit limits, requiring prepayments (partially or wholly), requiring product deliveries over defined time periods, and credit monitoring. While we believe our procedures are effective, we can provide no assurance that bad debt write-offs in the future may not be significant and any such non-payment problems could impact our results of operations and potentially limit our ability to make payments on our debt obligations.

         Our terminaling operations depend on pipelines to transport crude oil and natural gas liquids.

        We own 22 natural gas liquids terminals and seven crude oil terminals. These facilities depend on pipeline and storage systems that are owned and operated by third parties. Any interruption of service

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on the pipeline or lateral connections or adverse change in the terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport product to and from our facilities and have a corresponding material adverse effect on our revenues. In addition, the rates charged by the interconnected pipelines for transportation to and from our facilities affect the utilization and value of our terminals. We have historically been able to pass through the costs of pipeline transportation to our customers. However, if competing pipelines do not have similar annual tariff increases or service fee adjustments, such increases could affect our ability to compete, thereby adversely affecting our revenues.

         Our marketing operations depend on the availability of transportation and storage capacity.

        Our product supply is transported and stored on facilities owned and operated by third parties. Any interruption of service on the pipeline or storage companies or adverse change in the terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport natural gas and have a corresponding material adverse effect on our revenues. In addition, the rates charged by the interconnected pipelines for transportation affects the profitability of our operations.

         The financial results of our natural gas liquids businesses are seasonal and generally lower in the first and second quarters of our fiscal year, which may require us to borrow money to make distributions to our unitholders during these quarters.

        The natural gas liquids inventory we have pre-sold to customers is highest during summer months, and our cash receipts are lowest during summer months. As a result, our cash available for distribution for the summer is much lower than for the winter. With lower cash flow during the first and second fiscal quarters, we may be required to borrow money to pay distributions to our unitholders during these quarters. Any restrictions on our ability to borrow money could restrict our ability to pay the minimum quarterly distributions to our unitholders.

         A significant increase in fuel prices may adversely affect our transportation costs.

        Fuel is a significant operating expense for us in connection with the delivery of products to our customers. A significant increase in fuel prices will result in increased transportation costs to us. The price and supply of fuel is unpredictable and fluctuates based on events we cannot control, such as geopolitical developments, supply and demand for oil and gas, actions by oil and gas producers, war and unrest in oil producing countries and regions, regional production patterns and weather concerns. As a result, any increases in these prices may adversely affect our profitability and competitiveness.

         Some of our operations cross the United States/Canada border and are subject to cross-border regulation.

        Our cross-border activities subject us to regulatory matters, including import and export licenses, tariffs, Canadian and United States customs and tax issues and toxic substance certifications. Such regulations include the "Short Supply Controls" of the Export Administration Act, the North American Free Trade Agreement and the Toxic Substances Control Act. Violations of these licensing, tariff and tax reporting requirements could result in the imposition of significant administrative, civil and criminal penalties.

         The risk of terrorism and political unrest in various energy producing regions may adversely affect the economy and the price and availability of products.

        An act of terror in any of the major energy producing regions of the world could potentially result in disruptions in the supply of crude oil and natural gas, the major sources of propane, which could have a material impact on the availability and price of propane. Terrorist attacks in the areas of our

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operations could negatively impact our ability to transport propane to our locations. These risks could potentially negatively impact our results of operations.

         We depend on the leadership and involvement of key personnel for the success of our businesses.

        We have certain key individuals in our senior management who we believe are critical to the success of our business. The loss of leadership and involvement of those key management personnel could potentially have a material adverse impact on our business and possibly on the market value of our units.

         Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

        We expect that we will distribute all of our available cash to our unitholders and will rely primarily on external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, as well as reserves we have established to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

        In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our Credit Agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to service our debt obligations, including the notes.

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EXCHANGE OFFER

        We sold the old notes on October 16, 2013 pursuant to the purchase agreement, dated as of October 10, 2013, by and among us, our subsidiary guarantors and the initial purchasers named therein. The old notes were subsequently offered by the initial purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to non-U.S. persons pursuant to Regulation S under the Securities Act.

        We sold the old notes in transactions that were exempt from or not subject to the registration requirements under the Securities Act. Accordingly, the old notes are subject to transfer restrictions. In general, you may not offer or sell the old notes unless either they are registered under the Securities Act or the offer or sale is exempt from, or not subject to, registration under the Securities Act and applicable state securities laws.

        In connection with the sale of the old notes, we entered into a registration rights agreement with the initial purchasers of the old notes. In that agreement, we agreed to use our commercially reasonable efforts to file an exchange offer registration statement after the closing date following the offering of the old notes. Now, to satisfy our obligations under the registration rights agreement, we are offering holders of the old notes who are able to make certain representations described below the opportunity to exchange their old notes for the new notes in the exchange offer. The exchange offer will be open for a period of at least 20 business days. During the exchange offer period, we will exchange the new notes for all old notes properly surrendered and not withdrawn before the expiration date. The new notes will be registered under the Securities Act, and the transfer restrictions, registration rights and provisions for additional interest relating to the old notes will not apply to the new notes.

        For each old note surrendered to us pursuant to the exchange offer, the holder of such old note will receive a new note having a principal amount equal to that of the surrendered old note. Interest on each new note will accrue from the last interest payment date on which interest was paid on the surrendered old note. The registration rights agreement also provides an agreement to include in the prospectus for the exchange offer certain information necessary to allow a broker-dealer who holds old notes that were acquired for its own account as a result of market-making activities or other ordinary course trading activities (other than old notes acquired directly from us or one of our affiliates) to exchange such old notes pursuant to the exchange offer and to satisfy the prospectus delivery requirements in connection with resales of new notes received by such broker-dealer in the exchange offer. We agreed to use commercially reasonable efforts to maintain the effectiveness of the exchange offer registration statement for these purposes for a period ending on the earlier of 180 days from the date on which the exchange offer registration statement is declared effective and the date on which the broker-dealer is no longer required to deliver a prospectus in connection with market-making or other trading activities.

        The preceding agreement is needed because any broker-dealer who acquires old notes for its own account as a result of market-making activities or other trading activities is required to deliver a prospectus meeting the requirements of the Securities Act. This prospectus covers the offer and sale of the new notes pursuant to the exchange offer and the resale of new notes received in the exchange offer by any broker-dealer who held old notes acquired for its own account as a result of market-making activities or other trading activities, other than old notes acquired directly from us or one of our affiliates.

        Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the new notes issued pursuant to the exchange offer would in general be freely tradable after the exchange offer without further registration under the Securities Act. However, any

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purchaser of old notes who is an "affiliate" of ours or who intends to participate in the exchange offer for the purpose of distributing the related new notes:

        Each holder of the old notes (other than certain specified holders) who desires to exchange old notes for the new notes in the exchange offer will be required to make the representations described below under "—Procedures for Tendering—Your Representations to Us."

        We further agreed to file with the SEC a shelf registration statement to register for public resale old notes held by any holder who provides us with certain information for inclusion in the shelf registration statement if:

        We have agreed to use commercially reasonable efforts to file the shelf registration with the SEC on or before the 30 days after the occurrence of the events described in the first three bullets above, which date we refer to as the "shelf filing deadline," and to use commercially reasonable efforts to cause the shelf registration statement to be declared effective on or before 90 days after the shelf filing deadline. We have also agreed to use commercially reasonable efforts to keep the shelf registration statement continuously effective from the date on which the shelf registration statement is declared effective by the SEC until the earlier of the first anniversary of the effective date of such shelf registration statement and such time as all notes covered by the shelf registration statement have been sold or are freely tradeable. We refer to this period as the "shelf effectiveness period."

        If:

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then the Issuers and the subsidiary guarantors will pay liquidated damages to each holder of notes, with respect to the first 90-day period immediately following the occurrence of the first Registration Default in an amount equal to one quarter of one percent (0.25%) per annum on the principal amount of notes held by such holder. The amount of the liquidated damages will increase by an additional one-quarter of one percent (0.25%) per annum on the principal amount of notes with respect to each subsequent 90-day period until all Registration Defaults have been cured, up to a maximum amount of liquidated damages for all Registration Defaults of one-half of one percent (0.50%) per annum. All accrued liquidated damages will be paid by the Issuers (or the subsidiary guarantors, if applicable) in the manner provided for with respect to the payment of interest in the Indenture as more fully set forth in the Indenture and the notes. Following the cure of all Registration Defaults, the accrual of liquidated damages will cease.

        Holders of the old notes will be required to make certain representations to us (as described below under "—Procedures for Tendering") in order to participate in the exchange offer and will be required to deliver information to be used in connection with the shelf registration statement and to provide comments on the shelf registration statement within the time periods set forth in the registration rights agreement in order to have their old notes included in the shelf registration statement.

        If we effect the registered exchange offer, we will be entitled to close the registered exchange offer 20 business days after its commencement as long as we have accepted all old notes validly tendered in accordance with the terms of the exchange offer and no brokers or dealers continue to hold any old notes.

        This summary of the material provisions of the registration rights agreement does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all the provisions of the registration rights agreement, a copy of which is filed as an exhibit to the registration statement that includes this prospectus.

        Except as set forth above, after consummation of the exchange offer, holders of old notes that are the subject of the exchange offer will have no registration or exchange rights under the registration rights agreement. See "—Consequences of Failure to Exchange."

        Subject to the terms and conditions described in this prospectus and in the letter of transmittal, we will accept for exchange any old notes properly tendered and not withdrawn prior to 12:00 midnight, New York City time, at the end of the expiration date. We will issue new notes in a principal amount equal to the principal amount of old notes surrendered in the exchange offer. Old notes may be tendered only for new notes and only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.

        The exchange offer is not conditioned upon any minimum aggregate principal amount of old notes being tendered for exchange.

        As of the date of this prospectus, $450.0 million in aggregate principal amount of the old notes is outstanding. This prospectus and the letter of transmittal are being sent to all registered holders of old

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notes. There will be no fixed record date for determining registered holders of old notes entitled to participate in the exchange offer.

        We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Securities Exchange Act of 1934, as amended (the "Exchange Act") and the rules and regulations of the Securities and Exchange Commission. Old notes that the holders thereof do not tender for exchange in the exchange offer will remain outstanding and continue to accrue interest. These old notes will continue to be entitled to the rights and benefits such holders have under the indenture relating to the notes and the registration rights agreement.

        We will be deemed to have accepted for exchange properly tendered old notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the new notes from us.

        The exchange offer will expire at 12:00 midnight, New York City time, at the end of February 10, 2015, unless, in our sole discretion, we extend it.

        We expressly reserve the right, at any time or various times, to extend the period of time during which the exchange offer is open. We may delay acceptance of any old notes by giving oral or written notice of such extension to their holders at any time until the exchange offer expires or terminates. During any such extensions, all old notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.

        In order to extend the exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of old notes of the extension by a press release issued no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration date.

        Any such notice relating to the extension of the exchange offer will disclose the number of securities tendered as of the date of the notice, as required by Rule 14e-1(d) under the Exchange Act.

        We expressly reserve the right at our sole discretion:

        Following the commencement of the exchange offer, we currently anticipate that we would only delay accepting old notes tendered in the exchange offer due to an extension of the expiration date.

        We will follow any delay in acceptance, extension or termination as promptly as practicable by oral or written notice to the exchange agent.

        Any such delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by oral or written notice thereof to the registered holders of old notes. If we amend the

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exchange offer in a manner that we determine to constitute a material change, we will promptly disclose such amendment by means of a prospectus supplement. The prospectus supplement will be distributed to the registered holders of the old notes. Depending upon the significance of the amendment and the manner of disclosure to the registered holders, we may extend the exchange offer. In the event of a material change in the exchange offer, including the waiver by us of a material condition, we will extend the exchange offer period, if necessary, so that at least five business days remain in the exchange offer period following notice of the material change.

        If we delay accepting any old notes or terminate the exchange offer, we will promptly return any old notes deposited pursuant to the exchange offer as required by Rule 14e-1(c).

        We will not be required to accept for exchange, or exchange any new notes for, any old notes if the exchange offer, or the making of any exchange by a holder of old notes, would violate applicable law or any applicable interpretation of the staff of the SEC. Similarly, we may terminate the exchange offer as provided in this prospectus before accepting old notes for exchange in the event of such a potential violation.

        In addition, we will not be obligated to accept for exchange the old notes of any holder that has not made to us the representations described under "—Purpose and Effect of the Exchange Offer," "—Procedures for Tendering" and "Plan of Distribution" and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the issuance of the new notes under the Securities Act.

        We expressly reserve the right to amend or terminate the exchange offer, and to reject for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions to the exchange offer specified above. We will give prompt oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the old notes as promptly as practicable.

        These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times in our sole discretion prior to the expiration of the exchange offer. If we fail at any time to exercise any of these rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times prior to the expiration of the exchange offer.

        In addition, we will not accept for exchange any old notes tendered, and will not issue new notes in exchange for any such old notes, if at such time any stop order has been threatened or is in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture relating to the notes under the Trust Indenture Act of 1939, as amended (the "Trust Indenture Act").

        In order to participate in the exchange offer, you must properly tender your old notes to the exchange agent as described below. We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes, and you should follow carefully the instructions on how to tender your old notes. It is your responsibility to properly tender your notes. We have the right to waive any defects. However, we are not required to waive defects and are not required to notify you of defects in your tender.

        If you have any questions or need help in exchanging your notes, please call the exchange agent, whose address and phone number are set forth in "Prospectus Summary—The Exchange Offer—Exchange Agent."

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        All of the old notes were issued in book-entry form, and all of the old notes are currently represented by global certificates held for the account of DTC. We have confirmed with DTC that the old notes may be tendered using the Automated Tender Offer Program, or ATOP, instituted by DTC. The exchange agent will establish an account with DTC for purposes of the exchange offer promptly after the commencement of the exchange offer, and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer their old notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an "agent's message" to the exchange agent. The agent's message will state that DTC has received instructions from the participant to tender old notes and that the participant agrees to be bound by the terms of the letter of transmittal.

        By using the ATOP procedures to exchange old notes, you will not be required to deliver a letter of transmittal to the exchange agent. However, you will be bound by its terms just as if you had signed it.

        There is no procedure for guaranteed late delivery of the notes.

        We will determine, in our sole discretion, all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered old notes and withdrawal of tendered old notes. Our determination will be final and binding. We reserve the absolute right to reject any old notes not properly tendered or any old notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defects, irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of old notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of old notes will not be deemed made until such defects or irregularities have been cured or waived. Any old notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the letter of transmittal, promptly following the expiration date of the exchange.

        In all cases, we will issue new notes for old notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

        If we do not accept any tendered old notes for exchange or if old notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged old notes will be returned without expense to their tendering holder. Such non-exchanged old notes will be credited to an account maintained with DTC. These actions will occur promptly after the expiration or termination of the exchange offer.

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        By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

        Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 12:00 midnight, New York City time, at the end of the expiration date. For a withdrawal to be effective, you must comply with the appropriate procedures of DTC's ATOP system. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn old notes and otherwise comply with the procedures of DTC.

        We will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any old notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer.

        Any old notes that have been tendered for exchange but are not exchanged for any reason will be credited to an account maintained with DTC for the old notes. This crediting will take place promptly after withdrawal, rejection of tender or termination of the exchange offer. You may retender properly withdrawn old notes by following the procedures described under "—Procedures for Tendering" above at any time prior to 12:00 midnight, New York City time, at the end of the expiration date of the exchange offer.

        We will bear the expenses of soliciting tenders. The principal solicitation is being made by electronic mail; however, we may make additional solicitation by facsimile, telephone, mail or in person by our officers and regular employees and those of our affiliates.

        We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

        We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

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        We will pay all transfer taxes, if any, applicable to the exchange of old notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of old notes under the exchange offer.

        If you do not exchange new notes for your old notes under the exchange offer you will remain subject to the existing restrictions on transfer of the old notes. In general, you may not offer or sell the old notes unless the offer or sale is either registered under the Securities Act or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the old notes under the Securities Act.

        We will record the new notes in our accounting records at the same carrying value as the old notes. This carrying value is the aggregate principal amount of the old notes less any bond discount, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offer.

        Participation in the exchange offer is voluntary and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

        We may in the future seek to acquire untendered old notes in open market or privately-negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered old notes.

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RATIO OF EARNINGS TO FIXED CHARGES

        The following table presents the ratios of earnings to fixed charges of the Partnership for the periods indicated. For purposes of computing the ratios of earnings to fixed charges, earnings consist of income (loss) from continuing operations before income taxes plus fixed charges and loss (income) from continuing operations before income taxes attributable to noncontrolling interests. Fixed charges consists of interest expense plus loss on early extinguishment of debt and the portion of rental expense estimated to relate to interest. The portion of rental expense estimated to relate to interest represents one-third of total operating lease rental expense, which is the portion estimated to represent interest.

 
  NGL Energy Partners LP   NGL Supply, Inc.  
 
  Six
Months
Ended
September 30,
2014
  Year
Ended
March 31,
2014
  Year
Ended
March 31,
2013
  Year
Ended
March 31,
2012
  Six
Months
Ended
March 31,
2011
  Six
Months
Ended
September 30,
2010
  Year
Ended
March 31,
2010
 

Ratio of earnings to fixed charges

           (a)   1.53x     1.75x     1.91x     5.59x              (b)   6.32x  

(a)
Due to NGL Energy Partners LP's loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2014. NGL Energy Partners LP would have needed to generate an additional $60.1 million of earnings to achieve a ratio of 1:1.

(b)
Due to NGL Supply, Inc.'s loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2010. NGL Supply, Inc. would have needed to generate an additional $3.9 million of earnings to achieve a ratio of 1:1.

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USE OF PROCEEDS

        The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated by this prospectus, we will receive old notes in a like principal amount. The form and terms of the new notes are identical in all respects to the form and terms of the old notes, except the new notes will be registered under the Securities Act and will not contain restrictions on transfer, registration rights or provisions for additional interest. Old notes surrendered in exchange for the new notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the new notes will not result in any change in outstanding indebtedness.

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SELECTED CONSOLIDATED HISTORICAL FINANCIAL AND OPERATING DATA

        We were formed on September 8, 2010, but had no operations through September 30, 2010. In October 2010, we acquired the assets and operations of NGL Supply and Hicksgas. We do not have our own historical financial statements for periods prior to our formation. The following table shows selected historical financial and operating data for NGL Energy Partners LP and NGL Supply (the deemed acquirer for accounting purposes in our formation) for the periods and as of the dates indicated. The financial statements of NGL Supply became our historical financial statements for all periods prior to October 1, 2010. The following table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the financial statements and related notes of NGL Energy Partners LP included elsewhere in this prospectus.

        The selected consolidated historical financial data (excluding volume information) at September 30, 2014 and for the six months ended September 30, 2014 are derived from our unaudited historical consolidated financial statements included elsewhere in this prospectus. The selected consolidated historical financial data (excluding volume information) at March 31, 2014 and 2013 and for each of the three years in the period ended March 31, 2014 are derived from our audited historical consolidated financial statements included elsewhere in this prospectus. The selected consolidated historical financial data (excluding volume information) at March 31, 2012 and 2011 and for the six months ended March 31, 2011 are derived from our financial records. The selected consolidated historical financial data (excluding volume information) at September 30, 2010 and for the six months then ended and at March 31, 2010 and for the year then ended are derived from the financial records of NGL Supply.

 
   
  NGL Energy Partners LP   NGL Supply, Inc.  
 
  Six Months
Ended
September 30,
2014
  Year Ended March 31,   Six Months
Ended
March 31,
2011
  Six Months
Ended
September 30,
2010
   
 
 
  Year Ended
March 31,
2010
 
 
  2014   2013   2012  
 
   
  (in thousands, except per unit data)
 

Income Statement Data(1)

                                           

Total revenues

  $ 9,029,140   $ 9,699,274   $ 4,417,767   $ 1,310,473   $ 622,232   $ 316,943   $ 735,506  

Total cost of sales

    8,713,518     9,132,699     4,039,110     1,217,023     583,032     310,908     708,215  

Operating income (loss)

    (12,785 )   106,565     87,307     15,030     14,837     (3,795 )   6,661  

Interest expense

    (49,145 )   58,854     32,994     7,620     2,482     372     668  

Loss on early extinguishment of debt

            5,769                  

Net income (loss) attributable to parent equity

    (59,199 )   47,655     47,940     7,876     12,679     (2,515 )   3,636  

Basic and diluted earnings (loss) per common unit

    (0.93 )   0.51     0.96     0.32     1.16              

Basic earnings (loss) per common share

                                  (128.46 )   178.75  

Diluted earnings (loss) per common share

                                  (128.46 )   176.61  

Cash Flows Data(1)

                                           

Cash flows from operating activities

  $ (61,635 ) $ 85,236   $ 132,634   $ 90,329   $ 34,009   $ (30,749 ) $ 7,480  

Cash distributions paid per common unit (subsequent to IPO)

    1.14     2.01     1.69     0.85                    

Cash distributions per common unit (prior to IPO)

                      0.35                  

Cash distributions paid per common share

                                  357.09      

Capital expenditures:

                                           

Purchases of long-lived assets

    82,851     165,148     72,475     7,544     1,440     280     582  

Acquisitions of businesses, including additional consideration paid on prior period acquisitions

    658,764     1,268,810     490,805     297,401     17,400     123     3,113  

Balance Sheet Data—Period End(1)

                                           

Total assets

  $ 6,551,679   $ 4,167,223   $ 2,291,618   $ 749,519   $ 163,833   $ 148,596   $ 111,580  

Total long-term obligations, exclusive of current maturities

    2,437,351     1,639,578     742,641     199,389     65,936     18,940     8,851  

Redeemable preferred stock

                            3,000  

Total equity

    2,314,830     1,531,853     889,418     405,329     47,353     36,811     46,403  

Volume Information(1)

                                           

Retail propane and distillates sold (gallons)

    55,854     197,326     173,232     79,886     34,932     3,747     15,514  

Wholesale propane sold (gallons)(2)

    423,992     1,190,106     912,625     659,921     372,504     226,330     623,510  

Wholesale other products sold (gallons)

    384,235     786,671     505,529     134,999     49,465     46,092     53,878  

Crude oil sold (barrels)

    40,806     46,107     24,373                  

Water delivered (barrels)

    51,804     62,774     25,009                  

Refined products sold (gallons)

    1,221,949     412,974                      

(1)
The acquisitions of businesses affect the comparability of this information.
(2)
Includes intercompany volumes sold to our retail propane segment.

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BUSINESS

Overview

        We are a Delaware limited partnership formed in September 2010 by several investors ("IEP Parties"). As part of our formation, we acquired and combined the assets and operations of NGL Supply, Inc., primarily a wholesale propane and terminaling business founded in 1967, and Hicksgas, LLC and Hicksgas Gifford, Inc., primarily a retail propane business founded in 1940. Subsequent to our formation, we significantly expanded our operations through numerous business combinations. At March 31, 2014, our primary businesses include:

        We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products in back-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business, which purchases ethanol primarily at production facilities and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders. These businesses were acquired in our December 2013 acquisition of Gavilon, LLC ("Gavilon Energy").

        For more information regarding our operating segments, please see Note 13 to our audited consolidated financial statements included elsewhere in this prospectus.

Initial Public Offering

        On May 17, 2011, we completed our initial public offering ("IPO") and listed our common units on the New York Stock Exchange under the symbol "NGL." Upon the completion of our IPO, we had outstanding common units, subordinated units, a 0.1% general partner interest, and incentive distribution rights ("IDRs"). IDRs entitle the holder to specified increasing percentages of cash distributions as our per-unit cash distributions increase above specified levels.

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Acquisitions Subsequent to Initial Public Offering

        Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, including the following, among others:

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Primary Service Areas

        The following maps show the primary service areas of our businesses at various points in time, to illustrate the growth of our businesses:


Primary Service Areas at May 11, 2011

GRAPHIC

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Primary Service Areas at March 31, 2012

GRAPHIC


Primary Service Areas at March 31, 2013

GRAPHIC

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Primary Service Areas at March 31, 2014

GRAPHIC

Our Business Strategies

        Our principal business objective is to increase the quarterly distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business and its cash flows. We expect to achieve this objective by executing the following strategies:

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Our Competitive Strengths

        We believe that we are well-positioned to successfully execute our business strategies and achieve our principal business objectives because of the following competitive strengths:

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Our Businesses

Crude Oil Logistics

        Overview.    Our crude oil logistics segment purchases crude oil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. Our operations are centered near areas of high crude oil production, such as the Bakken Shale Basin in North Dakota, the Niobrara Shale Basin in Colorado, the Mississippi Lime Basin in Oklahoma, the Permian Basin in Texas and New Mexico, the Eagle Ford Basin in Texas, and the Anadarko Basin in Oklahoma and Texas.

        Operations.    We transport crude oil using the following assets:

        We contract for truck, rail, and barge transportation services from third parties and ship on common carrier pipelines. We own 60 pipeline injection facilities in Kansas, Oklahoma, North Dakota, New Mexico, Texas, and Montana. We lease six rail transload facilities and have throughput agreements at seven rail transload facilities in Colorado, Kansas, Louisiana, New Mexico, North Dakota, Oklahoma, and Texas.

        We own seven storage terminal facilities, as summarized below:

Location
  Storage Capacity
(barrels)
 

Cushing, Oklahoma

    4,140,000  

Catoosa, Oklahoma

    138,000  

Port Aransas, Texas

    120,000  

Rio Hondo, Texas

    80,000  

Wheatland, Wyoming

    80,000  

Seadrift, Texas

    25,000  

Sunray, Texas

    9,500  

        We lease 3.85 million barrels of storage capacity in Cushing, Oklahoma.

        We have two Gulf Coast terminal facilities that are under construction and are expected to be completed during the latter part of fiscal 2015 with a total expected storage capacity of 625,000 barrels. We also own a 50% interest in Glass Mountain, which owns a 210-mile crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma. This pipeline, which became operational in February 2014, has a capacity of 147,000 barrels per day.

        Customers.    Our customers include crude oil refiners and marketers. Approximately 60% of the revenues from our crude oil logistics segment during the year ended March 31, 2014 related to our ten

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largest customers of the segment. In addition to utilizing our assets to transport product we own, we also provide truck transportation, barge transportation, storage, and terminal throughput services to our customers.

        Competition.    We face significant competition, as many entities are engaged in the crude oil logistics business, some of which are larger and have greater financial resources than we do. The primary factors on which we compete are:

        Supply.    We obtain crude oil from a large base of suppliers, which consist primarily of crude oil producers. We currently purchase from 800 producers at 7,600 leases.

        Pricing Policy.    Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets, such as Cushing, Oklahoma. We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by entering into financial derivatives. We also seek to maximize margins on crude oil sales by combining crude oil of varying qualities (such as gravity, sulphur content, or mineral content).

        Billing and Collection Procedures.    As is customary in the crude oil industry, we generally receive payment from customers on a monthly basis. As a result, receivables from individual customers in our crude oil business are typically higher than the receivables from customers of our other segments. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our crude oil logistics customers. We believe the following procedures enhance our collection efforts with our crude oil logistics customers:

        Trade Names.    Our crude oil logistics business operates primarily under the NGL—Crude Logistics trade name.

Water Solutions

        Overview.    Our water solutions segment generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from crude oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons. Our facilities are located near fields

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with high levels of crude oil and natural gas production, such as the Pinedale Anticline Basin in Wyoming, the DJ Basin in Colorado, and the Permian and Eagle Ford Basins in Texas.

        Operations.    We own 23 wastewater processing facilities. The location of the facilities and the processing capacities at which the facilities currently operate are summarized below.

Location
  Processing
Capacity
(barrels per day)
 

Pinedale, Wyoming(A)(B)

    60,000  

Briggsdale, Colorado(C)(D)

    34,000  

Grover, Colorado(C)

    25,000  

Greeley, Colorado(B)

    18,000  

Platteville, Colorado(C)(E)

    16,200  

Kersey, Colorado(C)

    14,000  

LaSalle, Colorado(C)

    5,900  

Brighton, Colorado(C)

    5,100  

Big Lake, Texas(C)

    30,000  

Pecos, Texas(C)(F)

    23,000  

Carrizo Springs, Texas(B)

    22,500  

Charlotte, Texas(C)(F)

    22,000  

Cheapside, Texas(C)

    22,000  

Gillett, Texas(C)

    22,000  

Karnes City, Texas(C)

    22,000  

Artesia Wells, Texas(C)

    20,000  

Nixon, Texas(C)

    20,000  

Los Angeles, Texas(B)

    20,000  

Fowlerton, Texas(C)

    18,000  

Pearsall, Texas(B)

    17,000  

Cotulla, Texas(C)

    16,500  

Dilley Lea, Texas(B)

    15,000  

Andrews, Texas(C)

    12,000  

(A)
This facility has a design capacity of 60,000 barrels per day to process water to a recycle standard which also includes a design capacity of 20,000 barrels per day to process water to a discharge standard.

(B)
These facilities are located on land we lease.

(C)
These facilities are located on land we own.

(D)
The processing capacity listed above for this facility includes a design capacity of 12,000 barrels per day to process water to a recycle standard.

(E)
The processing capacity listed above for this facility includes a design capacity of 10,000 barrels per day to process water to a recycle standard.

(F)
We purchased these facilities effective March 1, 2014.

        Our customers bring wastewater generated by crude oil and natural gas exploration and production operations to our facilities for treatment. Once we take delivery of the water, the level of processing is determined by the ultimate disposition of the water.

        Our facility in Wyoming has the assets and technology needed to treat the water more extensively. At this facility, the water is recycled, rather than being disposed of in an injection well. We either process the water to the point where it can be returned to producers to be re-used in future drilling

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operations, or we treat the water to a greater extent, such that it exceeds the standards for drinking water, and can be returned to the ecosystem.

        Our facilities in Colorado dispose of wastewater primarily into deep underground formations via injection wells. Two of our facilities in Colorado have the assets and technology needed to treat the water to the point that we can sell the water back to producers for use in future drilling operations.

        Our facilities in Texas dispose of wastewater into deep underground formations via injection wells. We also operate a wastewater transportation business in Texas, whereby we transport wastewater via truck to processing facilities owned by us and other parties. We operate this business with 70 owned trucks, 20 owned trailers, and 80 frac tanks.

        Customers.    The customers of our Wyoming and Colorado facilities consist primarily of large exploration and production companies who conduct drilling operations near our facilities. The primary customers of our facility in Wyoming have committed to deliver a specified minimum volume to our facility under multi-year contracts. Certain other customers, primarily those of our facilities in Colorado, have committed to deliver to our facilities all wastewater produced at all wells in a designated area under multi-year contracts. The customers of our facilities in Texas consist primarily of wastewater transportation companies, although one customer has committed to deliver 50,000 barrels per day to our facilities in Texas. During the year ended March 31, 2014, 37% of the revenues of the water solutions segment were generated from our two largest customers of the segment, and 73% of the revenues of the segment were generated from our ten largest customers of the segment.

        Competition.    We compete with other processors of wastewater to the extent that other processors have facilities geographically close to our facilities. Location is an important consideration for our customers, who seek to minimize the cost of transporting the wastewater to disposal facilities. Our facilities are strategically located near areas of significant crude oil and natural gas production.

        Pricing Policy.    We generally charge customers a processing fee per barrel of wastewater processed. Certain of our contracts require the customer to deliver a specified minimum volume of wastewater over a specified period of time. We also generate revenue from the sale of hydrocarbons we recover in the process of treating the wastewater, which we take into consideration in negotiating the processing fees with our customers.

        Billing and Collection Procedures.    Our water solutions customers consist of large oil and natural gas producers, and also include smaller water transportation companies. We typically invoice customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our water solutions customers. We believe the following procedures enhance our collection efforts with our water solutions customers:

        Trade Names.    Our water solutions business operates primarily under the NGL—Water Solutions trade name.

        Technology.    We hold multiple patents for processing technologies. We own a research and development center, which we use to optimize treatment processes and cost minimization.

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Liquids

        Overview.    Our liquids segment provides natural gas liquids procurement, storage, transportation, and supply services to customers through assets owned by us and third parties. Our liquids business also supplies the majority of the propane for our retail propane business. We also sell butanes and natural gasolines to refiners and producers for use as blending stocks and diluent and assist refineries by managing their seasonal butane supply needs.

        Operations.    We procure natural gas liquids from refiners, gas processing plants, producers and other resellers for delivery to leased storage space, common carrier pipelines, railcar terminals, and direct to certain customers. Our customers take delivery by loading natural gas liquids into transport vehicles from common carrier pipeline terminals, private terminals, our terminals, directly from refineries and rail terminals, and by railcar.

        A portion of our wholesale propane gallons are presold to third-party retailers and wholesalers at a fixed price under back-to-back contracts. Back-to-back contracts, in which we balance our contractual portfolio by buying propane supply when we have a matching purchase commitment from our wholesale customers, protects our margins, and mitigates commodity price risk. Pre-sales also reduce the impact of warm weather because the customer is required to take delivery of the propane regardless of the weather. We generally require cash deposits from these customers. In addition, on a daily basis we have the ability to balance our inventory by buying or selling propane, butanes, and natural gasoline to refiners, resellers, and propane producers through pipeline inventory transfers at major storage hubs.

        In order to secure consistent supply during the heating season, we are often required to purchase volumes of propane during the entire fiscal year. In order to mitigate storage costs and price risk, we may sell those volumes at a lesser margin than we earn in our other wholesale operations.

        We purchase butane from refiners during the summer months, when refiners have a greater butane supply than they need, and sell butane to refiners during the winter blending season, when demand for butane is higher. We utilize a portion of our railcar fleet and a portion of our leased underground storage to store butane for this purpose.

        We also transport customer-owned natural gas liquids on our leased railcars and charge the customers a transportation service fee. In addition, we sub-lease railcars to certain customers.

        We also purchase and sell asphalt. We utilize leased railcars to move the asphalt from our suppliers to our customers.

        We own 22 natural gas liquids terminals and we lease a fleet of railcars. These assets give us the opportunity to access wholesale markets throughout the United States, and to move product to locations where demand is highest. We utilize these terminals and railcars primarily in the service of our wholesale operations, although we also provide transportation, storage, and throughput services to other parties to a lesser extent.

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        The following chart lists our natural gas liquids terminals and their throughput capacity:

Facility
  Throughput Capacity
(in gallons per day)
 

Rosemount, Minnesota

    1,441,000  

Lebanon, Indiana

    1,058,000  

West Memphis, Arkansas

    1,058,000  

Dexter, Missouri

    930,000  

East St. Louis, Illinois

    883,000  

Jefferson City, Missouri

    883,000  

Hutchinson, Kansas

    840,000  

St. Catherines, Ontario, Canada

    700,000  

Janesville, Wisconsin

    553,000  

Light, Arkansas

    524,400  

Rixie, Arkansas

    524,400  

Winslow, Arizona

    500,000  

Albuquerque, New Mexico

    408,000  

Kingsland, Arkansas

    405,000  

Portland, Maine

    360,000  

West Springfield, Massachusetts

    360,000  

Vancouver, Washington

    358,000  

Green Bay, Wisconsin

    310,000  

Thackerville, Oklahoma

    235,000  

Ritzville, Washington

    198,000  

Sidney, Montana

    180,000  

Shelton, Washington

    161,000  

        We have operating agreements with third parties for certain of our terminals. The terminals in East St. Louis, Illinois and Jefferson City, Missouri are operated for us by a third party for a monthly fee under an operating and maintenance agreement that has a term that expires in 2017. The terminal in St. Catherines, Ontario, Canada is operated by a third party under a year-to-year agreement.

        We own the terminal assets. We own the land on which 12 of the terminals are located and we either have easements or lease the land on which 10 of the terminals are located. The terminals in East St. Louis, Illinois and Jefferson City, Missouri have perpetual easements, and the terminal in St. Catherines, Ontario, Canada has a long-term lease that expires in 2022.

        We own 4 railcars and lease 3,700 additional railcars, of which 600 railcars are subleased to a third party. These include high pressure and general purpose railcars.

        We own 16 transloading units, which enable customers to transfer product from railcars to trucks. These transloading units can be moved to locations along a railroad where it is most convenient for customers to transfer their product.

        We lease natural gas liquids storage space to accommodate the supply requirements and contractual needs of our retail and wholesale customers. We lease storage space for natural gas liquids in various storage hubs in Arizona, Canada, Kansas, Michigan, Mississippi, Missouri, New York and Texas.

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        The following chart shows our leased storage space at natural gas liquids storage facilities and interconnects to those facilities:

 
  Leased Storage Space
(in gallons)
   
Storage Facility
  Beginning
April 1,
2014
  At
March 31,
2014
  Storage Interconnects

Conway, Kansas

    73,290,000     85,890,000   Connected to Enterprise Mid-America and NuStar Pipelines; Rail Facility

Borger, Texas

    42,000,000     31,500,000   Connected to ConocoPhillips Blue Line Pipeline

Bushton, Kansas

    10,500,000     12,600,000   Connected to ONEOK North System Pipeline

Mont Belvieu, Texas

    3,150,000     2,940,000   Connected to Enterprise Texas Eastern Products Pipeline

Carthage, Missouri

    7,560,000     7,560,000   Connected to Magellan Pipeline

Marysville, Michigan

    4,200,000     15,750,000   Connected to Cochin Pipeline

Hattiesburg, Mississippi

    6,930,000     7,350,000   Connected to Enterprise Dixie Pipeline; Rail Facility

Redwater, Alberta, Canada

    7,938,000     9,055,200   Connected to Cochin Pipeline; Rail Facility

Regina, Saskatchewan, Canada

    1,260,000       Connected to Cochin Pipeline; Rail Facility

Bath, New York

        10,122,000   Rail Facility

Adamana, Arizona

    1,398,600     1,680,000   Rail Facility

Corunna, Ontario, Canada

    2,100,000     2,100,000   Rail Facility
             

Total

    160,326,600     186,547,200    
             
             

        During the typical heating season from September 15 through March 15 each year, we have the right to utilize ConocoPhillips' capacity as a shipper on the Blue Line pipeline to transport natural gas liquids from our leased storage space to our terminals in East St. Louis, Illinois and Jefferson City, Missouri. During the remainder of the year, we have access to available capacity on the Blue Line pipeline on the same basis as other shippers.

        Customers.    Our liquids business serves 900 customers in 45 states. Our liquids business serves national, regional and independent retail, industrial, wholesale, petrochemical, refiner and natural gas liquids production customers. Our liquids business also supplies the majority of the propane for our retail propane business. We deliver the propane supply to our customers at terminals located on common carrier pipeline systems, rail terminals, refineries, and major United States propane storage hubs. For the year ended March 31, 2014, our ten largest liquids customers represented 35% of the total sales of our liquids business (exclusive of sales to our retail propane segment).

        Seasonality.    Our liquids business is affected by the weather in a similar manner as our retail propane business. However, we are able to partially mitigate the effects of seasonality by pre-selling a portion of our wholesale volumes to retailers and wholesalers and requiring the customer to take delivery regardless of the weather.

        Competition.    Our liquids business faces significant competition. The primary factors on which we compete are:

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        Our competitors generally include other natural gas liquids wholesalers and companies involved in the natural gas liquids midstream industry (such as terminal and refinery operations), some of which have greater financial resources than we do.

        Pricing Policy.    In our natural gas liquids business, we offer our customers three categories of contracts for propane sourced from common carrier pipelines:

        We use back-to-back contracts for many of our liquids segment sales to limit exposure to commodity price risk and protect our margins. We are able to match our supply and sales commitments by offering our customers purchase contracts with flexible price, location, storage, and ratable delivery. However, certain common carrier pipelines require us to keep minimum in-line inventory balances year round to conduct our daily business, and these volumes may not be matched with a purchase commitment.

        We generally require deposits from our customers for fixed priced future delivery of propane if the delivery date is more than 30 days after the time of contractual agreement.

        Billing and Collection Procedures.    Our liquids segment customers consist of commercial accounts varying in size from local independent distributors to large regional and national retailers. These sales tend to be large volume transactions that can range from 10,000 gallons to as much as 1,000,000 gallons, and deliveries can occur over time periods extending from days to as long as a year. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our wholesale customers. We believe the following procedures enhance our collection efforts with our wholesale customers:

        Trade Names.    Our liquids business operates primarily under the NGL—Liquids, Centennial Energy, and Centennial Gas Liquids trade names.

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Retail Propane

        Overview.    Our retail propane business consists of the retail marketing, sale and distribution of propane and distillates, including the sale and lease of propane tanks, equipment and supplies, to more than 290,000 residential, agricultural, commercial and industrial customers. We also sell propane to certain re-sellers. We purchase the majority of the propane sold in our retail propane business from our liquids business, which provides our retail propane business with a stable and secure supply of propane.

        Operations.    We market retail propane and distillates through our customer service locations. We sell propane primarily in rural areas, but we also have a number of customers in suburban areas where energy alternatives to propane such as natural gas are not generally available. We own or lease 92 customer service locations and 91 satellite distribution locations, with aggregate propane storage capacity of 10.7 million gallons and aggregate distillate storage capacity of 3.4 million gallons. Our customer service locations are staffed and operated to service a defined geographic market area and typically include a business office, product showroom, and secondary propane storage. Our satellite distribution locations, which are unmanned storage tanks, allow our customer service centers to serve an extended market area.

        Our customer service locations in Illinois and Indiana also rent 15,000 water softeners and filters, primarily to residential customers in rural areas to treat well water or other problem water. We sell water conditioning equipment and treatment supplies as well. Although the water conditioning portion of our retail propane business is small, it generates steady year round revenues. The customer bases in Illinois and Indiana for retail propane and water conditioning have significant overlap, providing the opportunity to cross-sell both products between those customer bases.

        The following table shows the number of our customer service locations and satellite distribution locations by state:

State
  Number of
Customer Service
Locations
  Number of
Satellite
Distribution
Locations
 

Illinois

    23     19  

Maine

    17     10  

Georgia

    11     3  

Massachusetts

    10     8  

Kansas

    5     27  

Indiana

    4     5  

Pennsylvania

    4     3  

Connecticut

    3     2  

North Carolina

    3     1  

Oregon

    2     1  

Washington

    2      

Mississippi

    1     3  

New Hampshire

    1     1  

Maryland

    1     1  

Rhode Island

    1     1  

Utah

    1     1  

Wyoming

    1     1  

Colorado

    1      

South Carolina

    1      

Delaware

        1  

New Jersey

        1  

Tennessee

        1  

Vermont

        1  
           

Total

    92     91  
           
           

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        We own 74 of our 92 customer service centers and 63 of our 91 satellite distribution locations, and we lease the remainder.

        Tank ownership at customer locations is an important component to our operations and customer retention. At March 31, 2014, we owned the following propane storage tanks:

        We also lease an additional 20 bulk storage tanks.

        At March 31, 2014, we owned a fleet of 370 bulk delivery trucks, 40 semi-tractors, 40 propane transport trailers and 480 other service trucks.

        Retail deliveries of propane are usually made to customers by means of our fleet of bulk delivery trucks. Propane is pumped from the bulk delivery truck, which holds 2,400 to 5,000 gallons, into a storage tank at the customer's premises. The capacity of these storage tanks ranges from 30 to 1,000 gallons. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of 5 to 25 gallons. These cylinders are typically picked up on a delivery route, refilled at our customer service locations, and then returned to the retail customer. Customers can also bring the cylinders to our customer service centers to be refilled.

        Approximately 73% of our residential customers receive their propane supply via our automatic route delivery program, which allows us to maximize our delivery efficiency. For these customers, our delivery forecasting software system utilizes a customer's historical consumption patterns combined with current weather conditions to more accurately predict the optimal time to refill the customer's tank. The delivery information is then uploaded to routing software to calculate the most cost effective delivery route. Our automatic delivery program promotes customer retention by providing an uninterrupted supply of propane and enables us to efficiently conduct route deliveries on a regular basis. Some of our purchase plans, such as level payment billing, fixed price, and price cap programs, further promote our automatic delivery program.

        Customers.    Our retail propane and distillate customers fall into three broad categories: residential, agricultural, and commercial and industrial. At March 31, 2014, our retail propane and distillate customers were comprised of:

        No single customer accounted for more than 1% of our retail propane volumes during the year ended March 31, 2014.

        Seasonality.    The retail propane and distillate business is largely seasonal due to the primary use of propane and distillates as heating fuels. In particular, residential and agricultural customers who use propane and distillates to heat homes and livestock buildings generally only need to purchase propane during the typical fall and winter heating season. Propane sales to agricultural customers who use propane for crop drying are also seasonal, although the impact on our retail propane volumes sold varies from year to year depending on the moisture content of the crop and the ambient temperature at the time of harvest. Propane and distillate sales to commercial and industrial customers, while affected by economic patterns, are not as seasonal as are sales to residential and agricultural customers.

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        Competition.    Our retail propane business faces significant competition. The primary factors on which we compete are:

        Our competitors generally include other propane retailers and companies involved in the sale of natural gas, fuel oil and electricity, some of which have greater financial resources than we do. We compete with alternative energy sources and with other companies engaged in the retail propane distribution business. Competition with other retail propane distributors in the propane industry is highly fragmented and generally occurs on a local basis with other large full-service, multi state propane marketers, smaller local independent marketers and farm cooperatives. Our customer service locations generally have one to five competitors in their market area.

        The competitive landscape of the markets that we serve has been fairly stable. Each customer service location operates in its own competitive environment, since retailers are located in close proximity to their customers due to delivery economics. Our customer service locations generally have an effective marketing radius of 25 to 65 miles, although in certain areas the marketing radius may be extended by satellite distribution locations.

        The ability to compete effectively depends on the ability to provide superior customer service, which includes reliability of supply, quality equipment, well-trained service staff, efficient delivery, 24-hours-a-day service for emergency repairs and deliveries, multiple payment and purchase options and the ability to maintain competitive prices. Additionally, we believe that our safety programs, policies and procedures are more comprehensive than many of our smaller, independent competitors, which offers a higher level of service to our customers. We also believe that our overall service capabilities and customer responsiveness differentiate us from many of our competitors.

        Supply.    Our retail propane segment purchases the majority of its propane from our liquids segment.

        Pricing Policy.    Our pricing policy is an essential element in the successful marketing of retail propane and distillates. We protect our margin by adjusting our retail propane pricing based on, among other things, prevailing supply costs, local market conditions, and input from management at our customer service locations. We rely on our regional management to set prices based on these factors. Our regional managers are advised regularly of any changes in the delivered cost of propane and distillates, potential supply disruptions, changes in industry inventory levels, and possible trends in the future cost of propane and distillates. We believe the market intelligence provided by our liquids business, combined with our propane and distillate pricing methods allows us to respond to changes in supply costs in a manner that protects our customer base and our margins.

        Billing and Collection Procedures.    In our retail propane business, our customer service locations are typically responsible for customer billing and account collection. We believe that this decentralized and more personal approach is beneficial because our local staff has more detailed knowledge of our customers, their needs, and their history than would an employee at a remote billing center. Our local staff often develops relationships with our customers that are beneficial in reducing payment time for a number of reasons:

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        Our retail propane customers must comply with our standards for extending credit, which typically includes submitting a credit application, supplying credit references, and undergoing a credit check with an appropriate credit agency.

        Trade Names.    We use a variety of trademarks and trade names that we own, including Hicksgas, Propane Central, Brantley Gas, Osterman, Pacer, Downeast Energy, Allied Propane, Lessig Oil and Propane, and Proflame, among others. We typically retain and continue to use the names of the companies that we acquire and believe that this helps maintain the local identification of these companies and contributes to their continued success. We regard our trademarks, trade names, and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products.

Refined Products

        Overview.    Our refined products marketing business purchases gasoline and diesel fuel primarily from eight suppliers and typically sells these products in back-to-back contracts to over 300 customers at a nationwide network of third-party owned terminaling and storage facilities. We lease 175,000 barrels of refined products storage on a third-party pipeline.

        Customers.    Our customers include convenience stores, petroleum-related transportation companies and railroad companies, among others. Approximately 41% of the revenues from our refined products segment during the year ended March 31, 2014 related to our ten largest customers of the segment.

        Competition.    We face significant competition, as many entities are engaged in the refined products business, some of which are larger and have greater financial resources than we do. The primary factors on which we compete are:

        Supply.    We obtain refined products primarily from eight suppliers, which consist primarily of large energy and petrochemicals companies.

        Pricing Policy.    Most of our contracts to purchase or sell refined products are at floating prices that are indexed to published rates in active markets. We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by entering into financial derivatives.

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        Billing and Collection Procedures.    Our refined products customers consist primarily of large energy and petrochemicals companies. We typically invoice these customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our refined products customers. We believe the following procedures enhance our collection efforts with our refined products customers:

Renewables

        Overview.    Our renewables business, including ethanol marketing and biodiesel marketing businesses, purchases ethanol primarily at production facilities, and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using 40 leased railcars operating primarily in Iowa, Oklahoma, Minnesota, Missouri, and Texas for sale to refiners and blenders. We also transport and market third-party owned ethanol for a service fee. In our ethanol business, we lease and sublease railcars. We lease 2.5 million gallons of biodiesel storage at a facility in Deer Park, Texas and have a terminaling agreement at a facility in Phoenix, Arizona, with a minimum monthly throughput requirement of one million gallons.

        Customers.    Our customers include crude oil refiners and blenders. Approximately 70% of the revenues from our renewables segment during the year ended March 31, 2014 related to our ten largest customers of the segment.

        Competition.    We face significant competition, as many entities are engaged in the renewables business, some of which are larger and have greater financial resources than we do. The primary factors on which we compete are:

        Supply.    We obtain renewables from production facilities in the Midwest and in Houston, Texas.

        Pricing Policy.    Most of our contracts to purchase or sell renewables are at floating prices that are indexed to published rates in active markets. We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by entering into financial derivatives.

        Billing and Collection Procedures.    Our renewables customers consist primarily of crude oil refiners and blenders. We typically invoice these customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our refined

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products customers. We believe the following procedures enhance our collection efforts with our renewables customers:

Employees

        At March 31, 2014, we had 2,500 full-time employees, of which 2,300 were operational and 200 were general and administrative. Fourteen of our employees at two of our locations are members of a labor union. We believe that our relations with our employees are satisfactory.

Government Regulation

Regulation of the Oil and Natural Gas Industries

        Regulation of Oil and Natural Gas Exploration, Production and Sales.    Sales of crude oil and natural gas liquids are not currently regulated and are transacted at market prices. In 1989, the United States Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas. The FERC, which has the authority under the Natural Gas Act to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all natural gas resellers subject to its regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or FERC (with respect to the resale of natural gas in interstate commerce), however, could re-impose price controls in the future.

        Exploration and production operations are subject to various types of federal, state and local regulation, including, but not limited to, permitting, well location, methods of drilling, well operations, and conservation of resources. While these regulations do not directly apply to our business, they may affect the businesses of certain of our customers and suppliers and thereby indirectly affect our business.

        Regulation of the Transportation and Storage of Natural Gas and Oil and Related Facilities.    FERC regulates oil pipelines under the Interstate Commerce Act and natural gas pipeline and storage companies under the Natural Gas Act, and Natural Gas Policy Act of 1978 (the "NGPA"), as amended by the Energy Policy Act of 2005. While this regulation does not currently apply directly to our facilities, it may affect the price and availability of supply and thereby indirectly affect our business. Additionally, contracts we enter into for the transportation or storage of natural gas or oil are subject to FERC regulation including reporting or other requirements. In addition, the intrastate transportation and storage of oil and natural gas is subject to regulation by the state in which such facilities are located and such regulation can affect the availability and price of our supply and have both a direct and indirect effect on our business.

        Anti-Market Manipulation Rules.    We are subject to the anti-market manipulation provisions in the Natural Gas Act and the NGPA, as amended by the Energy Policy Act of 2005, which authorizes FERC to impose fines of up to $1,000,000 per day per violation of the Natural Gas Act, the NGPA, or their implementing regulations. In addition, the Federal Trade Commission holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1,000,000 per violation.

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These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The Commodity Futures Trading Commission is directed under the Commodity Exchange Act to prevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to statutory authority, the Commodity Futures Trading Commission has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The Commodity Futures Trading Commission also has statutory authority to seek civil penalties of up to the greater of $1,000,000 per day per violation or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the Commodity Exchange Act. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation.

        Maritime Transportation.    The Jones Act is a federal law that restricts maritime transportation between locations in the United States to vessels built and registered in the United States and owned and manned by United States citizens. Since we engage in maritime transportation through our barge fleet between locations in the United States, we are subject to the provisions of the law. As a result, we are responsible for monitoring the ownership of our subsidiaries that engage in maritime transportation and for taking any remedial action necessary to insure that no violation of the Jones Act ownership restrictions occurs. The Jones Act also requires that all United States-flagged vessels be manned by United States citizens. Foreign-flagged seamen generally receive lower wages and benefits than those received by United States citizen seamen. This requirement significantly increases operating costs of United States-flagged vessel operations compared to foreign-flagged vessel operations. Certain foreign governments subsidize their nations' shipyards. This results in lower shipyard costs both for new vessels and repairs than those paid by United States-flagged vessel owners. The United States Coast Guard and American Bureau of Shipping maintain the most stringent regimen of vessel inspection in the world, which tends to result in higher regulatory compliance costs for United States-flagged operators than for owners of vessels registered under foreign flags of convenience.

Environmental Regulation

        General.    Our operations are subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. Accordingly, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

        Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for

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environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate.

        The following is a discussion of the material environmental laws and regulations that relate to our business.

        Hazardous Substances and Waste.    We are subject to various federal, state, and local environmental, health and safety laws and regulations governing the storage, distribution and transportation of natural gas liquids and the operation of bulk storage LPG terminals, as well as laws and regulations governing environmental protection, including those addressing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. Generally, these laws (i) regulate air and water quality and impose limitations on the discharge of pollutants and establish standards for the handling of solid and hazardous wastes; (ii) subject our operations to certain permitting and registration requirements; (iii) may result in the suspension or revocation of necessary permits, licenses and authorizations; (iv) impose substantial liabilities on us for pollution resulting from our operations; (v) require remedial measures to mitigate pollution from former or ongoing operations; (vi) and may result in the assessment of administrative, civil and criminal penalties for failure to comply with such laws. These laws include, among others, the Resource Conservation and Recovery Act ("RCRA"), the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), the Clean Air Act, the Occupational Safety and Health Act, the Homeland Security Act of 2002, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes. For example, as a flammable substance, propane is subject to risk management plan requirements under section 112(r) of the Clean Air Act.

        CERCLA, also known as the "Superfund" law, and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. While propane is not a hazardous substance within the meaning of CERCLA, other chemicals used in or generated by our operations may be classified as hazardous. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to strict and joint and several liability for the costs of investigating and cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

        RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency ("EPA"), most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Certain wastes associated with the production of oil and natural gas, as well as petroleum-contaminated media, are exempt from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated under RCRA's less stringent solid waste provisions, state laws or other federal laws. It is possible, however, that certain wastes now classified as non-hazardous could be classified as hazardous wastes in the future and therefore be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas wastes as "hazardous wastes." Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

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        We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to implement remedial measures to prevent or mitigate future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

        Oil Pollution Prevention.    Our operations involve the shipment of crude oil by barge through navigable waters of the United States. The Oil Pollution Prevention Act imposes liability for releases of oil from vessels or facilities into navigable waters. If a release of crude oil to navigable waters occurred during shipment or from a terminal, we could be subject to liability under the Oil Pollution Prevention Act. We are not currently aware of any facts, events, or conditions related to oil spills that could materially impact our operations or financial condition. In 1973, the EPA adopted oil pollution prevention regulations under the Clean Water Act. These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure ("SPCC") plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility's operations comply with the requirements. To be in compliance, the facility's SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. We maintain and implement such plans for our facilities.

        Air Emissions.    Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. Furthermore, we may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

        Water Discharges.    The Clean Water Act and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the United States and impose requirements affecting our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon or other constituent tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of

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storm water runoff from certain types of facilities. We have discharge permits in place for a number of our facilities. These permits may require us to monitor and sample the storm water runoff from such facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

        Underground Injection Control.    Our underground injection operations are subject to the Safe Drinking Water Act, as well as analogous state laws and regulations, which establish requirements for permitting, testing, monitoring, record keeping, and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our permits, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties for property damages and personal injuries.

        Hydraulic Fracturing.    The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We do not conduct any hydraulic fracturing activities. However, a portion of our customers' oil and natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process and our water solutions business treats and disposes of wastewater generated from natural gas production, including production utilizing hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of underground injection and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of the United States Congress. Congress will likely continue to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act's Underground Injection Control Program and/or to require disclosure of chemicals used in the hydraulic fracturing process. Federal agencies, including the EPA and the United States Department of the Interior, have asserted their regulatory authority to, for example, study the potential impacts of hydraulic fracturing on the environment, and initiate rulemakings to compel disclosure of the chemicals used in hydraulic fracturing operations, and establish pretreatment standards for wastewater from hydraulic fracturing operations. In addition, several states, including Texas, Colorado and California, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing, which include additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions, and/or temporary or permanent bans on hydraulic fracturing. We expect that scrutiny of hydraulic fracturing activities will continue in the future.

Greenhouse Gas Regulation

        There is a growing concern, both nationally and internationally, about climate change and the contribution of greenhouse gas emissions, most notably carbon dioxide, to global warming. In June 2009, the United States House of Representatives passed the ACES Act, also known as the Waxman Markey Bill. The ACES Act did not pass the United States Senate, however, and so was not enacted by the 111th Congress. The ACES Act would have established an economy-wide cap on emissions of greenhouse gases in the United States and would have required most sources of greenhouse gas emissions to obtain and hold "allowances" corresponding to their annual emissions of greenhouse gases. More recently, the Climate Protection Act of 2013 was introduced in the United States Senate in

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February 2013. The Climate Protection Act of 2013 would introduce a carbon tax on all fossil fuels extracted, manufactured, produced in, or imported into the United States. The bill has not been advanced out of a United States Senate committee. The ultimate outcome of any possible future legislative initiatives is uncertain. In addition, several states have already adopted some legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs, although in recent years some states have scaled back their commitment to greenhouse gas initiatives.

        On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings allowed the EPA to adopt and implement regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has issued a number of regulations addressing greenhouse gas emissions under the Clean Air Act, including: the greenhouse gas reporting rule; greenhouse gas standards applicable to heavy-duty and light-duty vehicles; a rule requiring stationary sources to address greenhouse gas emissions in Prevention of Significant Deterioration and Title V permits; and new source performance standards for greenhouse gas emissions from new power plants. The EPA's greenhouse gas permitting rule is currently being reviewed by the United States Supreme Court with a decision expected by June 2014. The outcome of the litigation is unknown. The EPA's greenhouse gas regulations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations and also could adversely affect demand for the products that we transport, store, process, or otherwise handle in connection with our services.

        Some scientists have suggested climate change from greenhouse gases could increase the severity of extreme weather, such as increased hurricanes and floods, which could damage our facilities. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our natural gas liquids is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for our products and services. If there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

        Because propane is considered a clean alternative fuel under the federal Clean Air Act Amendments of 1990, new climate change regulations may provide us with a competitive advantage over other sources of energy, such as fuel oil and coal.

        The trend of more expansive and stringent environmental legislation and regulations, including greenhouse gas regulation, could continue, resulting in increased costs of doing business and consequently affecting our profitability. To the extent laws are enacted or other governmental action is taken that restricts certain aspects of our business or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected.

Safety and Transportation

        All states in which we operate have adopted fire safety codes that regulate the storage and distribution of propane and distillates. In some states, state agencies administer these laws. In others, municipalities administer them. We conduct training programs to help ensure that our operations comply with applicable governmental regulations. With respect to general operations, each state in which we operate adopts National Fire Protection Association (the "NFPA"), Pamphlet Nos. 54 and No. 58, or comparable regulations, which establish a set of rules and procedures governing the safe handling of propane, and Pamphlet Nos. 30, 30A, 31, 385 and 395 which establish rules and procedures governing the safe handling of distillates, such as fuel oil. We believe that the policies and procedures

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currently in effect at all of our facilities for the handling, storage and distribution of propane and distillates and related service and installation operations are consistent with industry standards and are in compliance in all material respects with applicable environmental, health and safety laws.

        With respect to the transportation of propane, distillates, crude oil, and water, we are subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials and are administered by the United States Department of Transportation ("DOT"). Specifically, crude oil pipelines are subject to regulation by the DOT, through the Pipeline and Hazardous Materials Safety Administration ("PHMSA"), under the Hazardous Liquid Pipeline Safety Act of 1979 ("HLPSA"), which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the storage and transportation of hazardous liquids by and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations. The Pipeline Safety Act of 1992 added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, established safety standards for certain "regulated gathering lines," and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in high consequence areas ("HCAs"), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room management.

Railcar Regulation

        We transport a significant portion of our natural gas liquids and crude oil via rail transportation, and we own and lease a fleet of railcars for this purpose. Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, as well as other federal and state regulatory agencies.

Occupational Health Regulations

        The workplaces associated with our manufacturing, processing, terminal and storage facilities are subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. We believe we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. Our marine vessel operations are also subject to safety and operational standards established and monitored by the United States Coast Guard. In general, we expect to increase our expenditures relating to compliance with likely higher industry and regulatory safety standards such as those described above. However, these expenditures cannot be accurately estimated at this time, but we do not expect them to have a material adverse effect on our business.

Legal Proceedings

        We are involved from time to time in various legal proceedings and claims arising in the ordinary course of business. For information related to legal proceedings, please see the discussion under the caption "Legal Contingencies" in Note 10 to our audited consolidated financial statements in included elsewhere in this prospectus, which information is incorporated herein.

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Available Information on our Website

        Our website address is http://www.nglenergypartners.com. We make available on our website, free of charge, the periodic reports that we file with or furnish to the Securities and Exchange Commission ("SEC"), as well as all amendments to these reports, as soon as reasonably practicable after such reports are filed with or furnished to the SEC. The information contained on, or connected to, our website is not incorporated by reference into this prospectus.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

Overview

        We are a Delaware limited partnership formed in September 2010. NGL Energy Holdings LLC serves as our general partner. As part of our formation, we acquired and combined the assets and operations of NGL Supply, which was primarily a wholesale propane and terminaling business that was founded in 1967, and Hicksgas, which was primarily a retail propane business that was founded in 1940. We completed an IPO in May 2011. At the time of our IPO, we owned and operated retail propane and wholesale natural gas liquids businesses. Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, as described under "Business—Acquisitions Subsequent to Initial Public Offering."

        At March 31, 2014, our primary businesses include:

        We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products in back-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business, which purchases ethanol primarily at production facilities and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders. These businesses were acquired in our December 2013 acquisition of Gavilon Energy.

        At September 30, 2014, our operations include:

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Crude Oil Logistics

        Our crude oil logistics business purchases crude oil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. We attempt to reduce our exposure to price fluctuations by using back-to-back contracts whenever possible. In addition, we enter into forward contracts, financial swaps, and commodity spread trades as economic hedges of our physical forward sales and purchase contracts with our customers and suppliers.

        Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets, such as Cushing, Oklahoma. We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by entering into financial derivatives. We utilize our transportation assets to move crude oil from the wellhead to the highest value market. The spread between crude oil prices in different markets can fluctuate widely, which may expand or limit our opportunity to generate margins by transporting crude oil to different markets. We also seek to maximize margins by blending crude oil of varying properties.

        The range of low and high spot prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma and the prices at March 31, 2014 were as follows:

 
  Spot Price Per Barrel  
Year Ended:
  Low   High   At Period
End
 

March 31, 2014

  $ 86.68   $ 110.53   $ 101.58  

March 31, 2013

    77.69     106.16     97.23  

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        The range of low and high spot prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma and the prices at September 30, 2014 were as follows:

 
  Spot Price Per Barrel  
 
  Low   High   At Period End  

Three Months Ended September 30,

                   

2014

  $ 91.16   $ 105.34   $ 91.16  

2013

    97.99     110.53     102.33  

Six Months Ended September 30,

                   

2014

  $ 91.16   $ 107.26   $ 91.16  

2013

    86.68     110.53     102.33  

        We believe volatility in commodity prices will continue, and our ability to adjust and manage this volatility may impact our financial results.

Water Solutions

        Our water solutions business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons. Our water processing facilities are strategically located near areas of high crude oil and natural gas production. A significant factor affecting the profitability of our water solutions segment is the extent of exploration and production in the areas near our facilities, which is based upon producers' expectations about the profitability of drilling new wells. The primary customers of our facility in Wyoming have committed to deliver a specified minimum volume of water to our facility under long-term contracts. The primary customers of our facilities in Colorado have committed to deliver to our facilities all wastewater produced at wells in a designated area. Most of the customers at our other facilities in Texas are not under volume commitments, other than one customer that has committed to deliver 50,000 barrels per day to our facilities.

Liquids

        Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, petrochemical plants, and other participants in the wholesale markets. Our liquids segment owns 22 terminals and operates a fleet of owned and leased railcars and leases underground storage capacity. We attempt to reduce our exposure to the impact of price fluctuations by using back-to-back contracts and pre-sale agreements that allow us to lock in a margin on a percentage of our winter volumes. We also attempt to reduce our exposure to the impact of price fluctuations by entering into swap agreements whereby we agree to pay a floating rate and receive a fixed rate on a specified notional amount of product. We enter into these agreements as economic hedges against the potential decline in the value of a portion of our inventory.

        Our wholesale business is a "cost-plus" business that is affected both by price fluctuations and volume variations. We establish our selling price based on a pass-through of our product supply, transportation, handling, storage and capital costs plus an acceptable margin. The margins we realize in our wholesale business are substantially less on a per gallon basis than our retail propane business.

        Weather conditions and gasoline blending have a significant impact on the demand for propane and butane, and sales volumes and prices are typically higher during the colder months of the year. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

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        The range of low and high spot propane prices per gallon at Conway, Kansas and Mt. Belvieu, Texas, two of our main pricing hubs, and the prices at March 31, 2014 were as follows:

 
  Conway, Kansas   Mt. Belvieu, Texas  
 
  Spot Price
Per Gallon
   
  Spot Price
Per Gallon
   
 
 
  Spot Price
Per Gallon
At Period End
  Spot Price
Per Gallon
At Period End
 
Year Ended:
  Low   High   Low   High  

March 31, 2014

  $ 0.77   $ 4.33   $ 1.03   $ 0.81   $ 1.73   $ 1.06  

March 31, 2013

    0.50     0.96     0.90     0.71     1.22     0.96  

March 31, 2012

    0.90     1.49     0.98     1.17     1.63     1.24  

        The range of low and high spot butane prices per gallon at Mt. Belvieu, Texas and the prices at March 31, 2014 were as follows:

 
  Spot Price Per Gallon  
Year Ended:
  Low   High   At Period End  

March 31, 2014

  $ 1.08   $ 1.64   $ 1.26  

March 31, 2013

    1.14     1.93     1.45  

        The range of low and high spot propane prices per gallon at Conway, Kansas and Mt. Belvieu, Texas, two of our main pricing hubs, and the prices at period end were as follows:

 
  Conway, Kansas   Mt. Belvieu, Texas  
 
  Spot Price Per Gallon   Spot Price Per Gallon  
 
  Low   High   At Period End   Low   High   At Period End  

Three Months Ended September 30,

                                     

2014

  $ 1.00   $ 1.10   $ 1.03   $ 0.99   $ 1.11   $ 1.04  

2013

    0.81     1.16     1.01     0.86     1.19     1.05  

Six Months Ended September 30,

                                     

2014

  $ 0.96   $ 1.13   $ 1.03   $ 0.99   $ 1.13   $ 1.04  

2013

    0.77     1.16     1.01     0.81     1.19     1.05  

        The range of low and high spot butane prices per gallon at Mt. Belvieu, Texas and the prices at period end were as follows:

 
  Spot Price Per Gallon  
 
  Low   High   At Period End  

Three Months Ended September 30,

                   

2014

  $ 1.21   $ 1.30   $ 1.22  

2013

    1.19     1.44     1.38  

Six Months Ended September 30,

                   

2014

  $ 1.20   $ 1.30   $ 1.22  

2013

    1.08     1.44     1.38  

        We believe volatility in commodity prices will continue, and our ability to adjust and manage this volatility may impact our financial results.

Retail Propane

        Our retail propane segment sells propane, distillates, and equipment and supplies to residential, agricultural, commercial, and industrial end users. Our retail propane segment purchases the majority of its propane from our liquids segment. Our retail propane segment generates margins based on the difference between the wholesale cost of product and the selling price of the product in the retail markets. These margins fluctuate over time due to supply and demand conditions. Weather conditions

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have a significant impact on our sales volumes and prices, as a significant portion of our sales are to residential customers who purchase propane and distillates for home heating purposes.

        A significant factor affecting the profitability of our retail propane segment is our ability to maintain our realized product margin on a cents per gallon basis. Product margin is the differential between our sales prices and our total product costs, including transportation and storage. Historically, we have been successful in passing on price increases to our customers. We monitor propane prices daily and adjust our retail prices to maintain expected margins by passing on the wholesale costs to our customers. We believe that volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.

        In periods of significant propane price increases we have experienced, and expect to continue to experience, conservation of propane used by our customers that could result in a decline in our sales volumes, revenues and gross margins. In periods of decreasing propane costs, we have experienced an increase in our product margin. The retail propane business is weather-sensitive and subject to seasonal volume variations due to propane's primary use as a heating source in residential and commercial buildings and for agricultural purposes. Typically, over 70% of our retail volume is sold during the peak heating season from October through March. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

Refined Products

        Our refined products marketing business purchases gasoline and diesel fuel primarily from eight suppliers, and sells to over 300 customers. We purchase and sell these products at a nationwide network of third-party owned terminaling and storage facilities. We typically sell the product at the same time it is purchased in back-to-back transactions.

Renewables

        Our ethanol marketing business purchases ethanol primarily at production facilities, and transports the ethanol for sale at various locations to refiners and blenders. We also transport and market third-party owned ethanol for a service fee.

        Our biodiesel marketing business purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product on leased railcars for sale to refiners and blenders. We lease biodiesel storage at facilities in Phoenix, Arizona and Deer Park, Texas.

Recent Developments

        Acquisitions of businesses have had a significant impact on the comparability of our results of operations from fiscal 2012 through 2014. These transactions are described under "Business—Acquisitions Subsequent to Initial Public Offering."

Development of Crude Oil Rail Transloading Facility

        On October 2, 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments, capable of handling unit trains west of Albuquerque, New Mexico in the San Juan Basin. We expect the terminal to be completed in the third quarter of calendar year 2015 and, we expect the terminal to have multiple inbound truck unloading bays, an initial outbound capacity of at least two unit trains per week, and over 240,000 barrels of storage.

Grand Mesa Pipeline, LLC

        On September 5, 2014, we formed the Grand Mesa Pipeline, LLC ("Grand Mesa") joint venture in which we have a 50% ownership interest. Grand Mesa expects to build a crude oil pipeline with

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initial capacity exceeding 130,000 barrels per day, originating in Weld County, Colorado, and terminating at our crude oil storage terminal in Cushing, Oklahoma.

TransMontaigne Inc.

        On July 1, 2014, we acquired TransMontaigne Inc. ("TransMontaigne") for $174.2 million of cash, net of cash acquired. As part of this transaction, we also purchased $380.4 million of inventory from the previous owner of TransMontaigne (including $346.9 million paid at closing and $33.5 million subsequently paid as the working capital settlement process progressed). The operations of TransMontaigne include the marketing of refined products and crude oil. As part of this transaction, we acquired the 2.0% general partner interest, the incentive distribution rights, and a 19.7% limited partner interest in TLP, and assumed certain terminaling service agreements with TLP from an affiliate of the previous owner of TransMontaigne. The acquisition agreement contemplates a post-closing adjustment to the purchase price for certain working capital items. We estimate that we will pay an additional $27.5 million once the working capital settlement process has been completed.

        On July 10, 2014, we submitted a nonbinding proposal to the conflicts committee of the board of directors of TLP's general partner. Under this proposal, each outstanding unit of TLP would be exchanged for one of our common units. On August 15, 2014, we and TLP's general partner terminated discussions regarding our previously submitted nonbinding proposal to acquire the outstanding common units of TLP.

Water Solutions Facilities

        As described below, we are party to a development agreement that provides us a right to purchase water disposal facilities developed by the other party to the agreement. During the six months ended September 30, 2014, we purchased four water disposal facilities under this development agreement. We also purchased a 75% interest in one additional water disposal facility in July 2014 from a different seller. On a combined basis, we paid $82.9 million of cash for these five water disposal facilities.

        During October and November 2014, we purchased five facilities under this development agreement and paid $52.2 million of cash for these facilities.

Water Supply Company

        In June 2014, we acquired an interest in a water supply company that expands our water solutions business in the DJ Basin.

Summary Discussion of Operating Results for the Three Months Ended September 30, 2014

        During the three months ended September 30, 2014, we generated operating income of $7.8 million, compared to operating income of $9.9 million during the three months endedSeptember 30, 2013.

        Our crude oil logistics segment generated operating income of less than $0.1 million during the three months ended September 30, 2014, compared to operating income of $5.9 million during the three months ended September 30, 2013. Spreads between the price of crude oil in different markets narrowed during the three months ended September 30, 2013 and remained narrow, which reduced our opportunity to generate increased margins by transporting crude oil from lower-price markets to higher-price markets. In addition, prices declined steadily during the three months ended September 30, 2014, which adversely impacted our margins.

        Our water solutions segment generated operating income of $14.8 million during the three months ended September 30, 2014, compared to operating income of $2.9 million during the three months ended September 30, 2013. This increase was due in part to an increase in the volume of wastewater

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processed, which was due to increased demand for existing facilities and to the development and acquisition of new facilities.

        Our liquids segment generated operating income of $10.9 million during the three months ended September 30, 2014, compared to operating income of $14.6 million during the three months ended September 30, 2013. Although sales volumes were higher during the three months ended September 30, 2014 than during the three months ended September 30, 2013, product margins were similar. This was due in part to the impact of unrealized gains on derivatives, which reduced cost of sales by $0.3 million during the three months ended September 30, 2014 and by $3.3 million during the three months ended September 30, 2013. Operating and general and administrative expenses were higher during the three months ended September 30, 2014 than during the three months ended September 30, 2013, due to expanded operations. Due to the seasonal nature of demand for natural gas liquids, sales volumes of our liquids segment are typically lower during the first and second quarters of the fiscal year than during the third and fourth quarters of the fiscal year.

        Our retail propane segment generated an operating loss of $3.1 million during the three months ended September 30, 2014, compared to an operating loss of $4.5 million during the three months ended September 30, 2013. Sales volumes increased due to high demand as a result of cold weather conditions during the previous winter. Due to the seasonal nature of demand for propane, sales volumes of our retail propane business typically are lower during the first and second quarters of the fiscal year than during the third and fourth quarters of the fiscal year.

        Our refined products and renewables segment generated operating income of $8.8 million during the three months ended September 30, 2014. Our refined products and renewables segment began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne.

        We recorded $3.7 million of earnings from our equity method investments during the three months ended September 30, 2014. Most of our equity method investments were acquired in our December 2013 acquisition of Gavilon Energy and our July 2014 acquisition of TransMontaigne.

        We incurred interest expense of $28.7 million during the three months ended September 30, 2014, compared to interest expense of $11.1 million during the three months ended September 30, 2013. The increase was due primarily to borrowings to finance acquisitions.

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Consolidated Results of Operations

        The following table summarizes our historical unaudited condensed consolidated statements of operations for the periods indicated:

 
  Three Months Ended
September 30,
  Six Months Ended
September 30,
 
 
  2014   2013   2014   2013  
 
  (in thousands)
 

Total revenues

  $ 5,380,526   $ 1,593,937   $ 9,029,140   $ 2,979,894  

Total cost of sales

    5,179,465     1,488,850     8,713,518     2,791,926  

Operating and general and administrative expenses

    143,192     70,081     238,933     137,580  

Depreciation and amortization

    50,099     25,061     89,474     47,785  
                   

Operating income (loss)

    7,770     9,945     (12,785 )   2,603  

Earnings of unconsolidated entities

    3,697         6,262      

Interest expense

    (28,651 )   (11,060 )   (49,145 )   (21,682 )

Other, net

    (617 )   419     (1,008 )   469  
                   

Loss before income taxes

    (17,801 )   (696 )   (56,676 )   (18,610 )

Income tax (provision) benefit

    1,922     (236 )   887     170  
                   

Net loss

    (15,879 )   (932 )   (55,789 )   (18,440 )

Less: Net income allocated to general partner

    (11,056 )   (2,451 )   (20,437 )   (4,139 )

Less: Net income attributable to noncontrolling interests

    (3,345 )   (9 )   (3,410 )   (134 )
                   

Net loss attributable to parent equity

  $ (30,280 ) $ (3,392 ) $ (79,636 ) $ (22,713 )
                   
                   

        See the detailed discussion of revenues, cost of sales, operating expenses, general and administrative expenses, depreciation and amortization expense and operating income by segment below. The acquisitions described above had a significant impact on the comparability of our results of operations during the three months and six months ended September 30, 2014 and 2013.

Segment Operating Results for the Three Months Ended September 30, 2014 and 2013

Items Impacting the Comparability of Our Financial Results

        Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of Gavilon Energy in December 2013 and TransMontaigne in July 2014. We expanded our water solutions business through several acquisitions of water disposal and transportation businesses, including OWL in August 2013, Coastal in September 2013, and other water disposal facilities subsequent to September 30, 2013. Our refined products and renewables businesses began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne. The results of operations of our liquids and retail propane segments are impacted by seasonality, primarily due to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our sales volumes and revenues. For these and other reasons, our results of operations for the three months ended September 30, 2014 are not necessarily indicative of the results to be expected for the full fiscal year.

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Volumes

        The following table summarizes the volume of product sold and water delivered during the three months ended September 30, 2014 and 2013. Volumes shown in the following table include intersegment sales.

 
  Three Months Ended
September 30,
   
 
Segment
  2014   2013   Change  
 
  (in thousands)
 

Crude oil logistics

                   

Crude oil sold (barrels)

    21,549     9,280     12,269  

Water solutions

   
 
   
 
   
 
 

Water delivered (barrels)

    30,869     16,459     14,410  

Liquids

   
 
   
 
   
 
 

Propane sold (gallons)

    240,234     183,415     56,819  

Other products sold (gallons)

    197,510     195,292     2,218  

Retail propane

   
 
   
 
   
 
 

Propane sold (gallons)

    23,551     20,599     2,952  

Distillates sold (gallons)

    3,434     3,072     362  

Refined products and renewables

   
 
   
 
   
 
 

Refined products sold (gallons)

    890,141         890,141  

Renewable products sold (gallons)

    51,557         51,557  

Operating Income (Loss) by Segment

        Our operating income (loss) by segment is as follows:

 
  Three Months Ended
September 30,
   
 
Segment
  2014   2013   Change  
 
  (in thousands)
 

Crude oil logistics

  $ 38   $ 5,884   $ (5,846 )

Water solutions

    14,792     2,913     11,879  

Liquids

    10,929     14,605     (3,676 )

Retail propane

    (3,062 )   (4,520 )   1,458  

Refined products and renewables

    8,822         8,822  

Corporate and other

    (23,749 )   (8,937 )   (14,812 )
               

Operating income

  $ 7,770   $ 9,945   $ (2,175 )
               
               

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Crude Oil Logistics

        The following table summarizes the operating results of our crude oil logistics segment for the periods indicated:

 
  Three Months Ended
September 30,
   
 
 
  2014   2013   Change  
 
  (in thousands)
 

Revenues:

                   

Crude oil sales

  $ 2,108,117   $ 1,013,061   $ 1,095,056  

Crude oil transportation and other

    13,082     9,794     3,288  
               

Total revenues(1)

    2,121,199     1,022,855     1,098,344  

Expenses:

                   

Cost of sales

    2,093,744     1,000,982     1,092,762  

Operating expenses

    12,432     11,760     672  

General and administrative expenses

    5,745     899     4,846  

Depreciation and amortization expense

    9,240     3,330     5,910  
               

Total expenses

    2,121,161     1,016,971     1,104,190  
               

Segment operating income

  $ 38   $ 5,884   $ (5,846 )
               
               

(1)
Revenues include $10.1 million and $8.8 million of intersegment sales during the three months ended September 30, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

        Revenues.    Our crude oil logistics segment generated $2.1 billion of revenue from crude oil sales during the three months ended September 30, 2014, selling 21.5 million barrels at an average price of $97.83 per barrel. During the three months ended September 30, 2013, our crude oil logistics segment generated $1.0 billion of revenue from crude oil sales, selling 9.3 million barrels at an average price of $109.17 per barrel.

        Crude oil transportation and other revenues of our crude oil logistics segment were $13.1 million during the three months ended September 30, 2014, compared to $9.8 million of crude oil transportation and other revenues during the three months ended September 30, 2013. This increase was due primarily to the Gavilon acquisition in December 2013.

        Cost of Sales.    Our cost of crude oil sold was $2.1 billion during the three months ended September 30, 2014, as we sold 21.5 million barrels at an average cost of $97.16 per barrel. Our cost of sales during the three months ended September 30, 2014 was reduced by $0.7 million of net unrealized gains on derivatives. During the three months ended September 30, 2013, our cost of crude oil sold was $1.0 billion, as we sold 9.3 million barrels at an average cost of $107.86 per barrel. Our cost of sales during the three months ended September 30, 2013 was increased by $3.1 million of net unrealized losses on derivatives.

        The most significant drivers of the increase in our volumes, revenues, and cost of sales were the acquisitions of Gavilon Energy in December 2013 and TransMontaigne in July 2014. Spreads between the price of crude oil in different markets narrowed during the three months ended September 30, 2013 and remained narrow, which reduced our opportunity to generate increased margins by transporting crude oil from lower-price markets to higher-price markets.

        Operating Expenses.    Our crude oil logistics segment incurred $12.4 million of operating expenses during the three months ended September 30, 2014, compared to $11.8 million of operating expenses during the three months ended September 30, 2013.

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        General and Administrative Expenses.    Our crude oil logistics segment incurred $5.7 million of general and administrative expenses during the three months ended September 30, 2014, compared to $0.9 million of general and administrative expenses during the three months ended September 30, 2013. This increase was due to the acquisitions of Gavilon Energy in December 2013 and TransMontaigne in July 2014. General and administrative expenses during the three months ended September 30, 2014 were increased by $2.2 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. General and administrative expenses during the three months ended September 30, 2014 were also increased by $1.2 million of compensation expense related to termination benefits for certain TransMontaigne employees.

        Depreciation and Amortization Expense.    Our crude oil logistics segment incurred $9.2 million of depreciation and amortization expense during the three months ended September 30, 2014, compared to $3.3 million of depreciation and amortization expense during the three months ended September 30, 2013. This increase was primarily due to acquisitions and capital expansions.

        Operating Income.    Our crude oil logistics segment generated operating income of less than $0.1 million during the three months ended September 30, 2014, compared to operating income of $5.9 million during the three months ended September 30, 2013. Operating income during the three months ended September 30, 2014 was increased by $0.7 million of net unrealized gains on derivatives. Operating income during the three months ended September 30, 2013 was reduced by $3.1 million of net unrealized losses on derivatives. Spreads between the price of crude oil in different markets narrowed during the three months ended September 30, 2013 and remained narrow, which reduced our opportunity to generate increased margins by transporting crude oil from lower-price markets to higher-price markets.

Water Solutions

        The following table summarizes the operating results of our water solutions segment for the periods indicated:

 
  Three Months Ended
September 30,
  Change  
 
  2014   2013   Acquisitions(1)   Other  
 
  (in thousands)
 

Revenues:

                         

Water treatment and disposal

  $ 47,572   $ 28,823   $ 14,861   $ 3,888  

Water transportation

    5,147     5,367     1,354     (1,574 )
                   

Total revenues

    52,719     34,190     16,215     2,314  

Expenses:

                         

Cost of sales

    (9,439 )   3,782     1,152     (14,373 )

Operating expenses

    29,019     15,003     13,947     69  

General and administrative expenses

    774     1,054     126     (406 )

Depreciation and amortization expense

    17,573     11,438     5,708     427  
                   

Total expenses

    37,927     31,277     20,933     (14,283 )
                   

Segment operating income

  $ 14,792   $ 2,913   $ (4,718 ) $ 16,597  
                   
                   

(1)
Represents the change in revenues and expenses attributable to acquisitions subsequent to June 30, 2013. The cost of sales amount shown in this column does not include derivative gains and losses, as these cannot be attributed to specific facilities.

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        Revenues.    The acquisitions subsequent to June 30, 2013 generated $19.4 million of treatment and disposal revenue during the three months ended September 30, 2014, taking delivery of 14.0 million barrels of wastewater at an average revenue of $1.39 per barrel. Exclusive of the acquisitions subsequent to June 30, 2013, our water solutions segment generated $28.2 million of treatment and disposal revenue during the three months ended September 30, 2014, taking delivery of 16.9 million barrels of wastewater at an average revenue of $1.67 per barrel. The acquisitions subsequent toJune 30, 2013 generated $4.5 million of treatment and disposal revenue during the three months ended September 30, 2013, taking delivery of 2.7 million barrels of wastewater at an average revenue of $1.68 per barrel. Exclusive of the acquisitions subsequent to June 30, 2013, our water solutions segment generated $24.3 million of treatment and disposal revenue during the three months ended September 30, 2014, taking delivery of 13.8 million barrels of wastewater at an average revenue of $1.76 per barrel. The primary reasons for the increase in revenues and water delivered were acquisitions made subsequent to June 30, 2013, including our acquisitions of OWL and Coastal, and to an increase in water volumes processed due to higher demand from customers.

        Water transportation revenues decreased by $0.2 million during the three months ended September 30, 2014 compared to the three months ended September 30, 2013. During September 2014, we sold our water transportation business in order to focus our efforts on water processing. As part of this transaction, the buyer of the transportation business committed to deliver to our facilities substantially all of the water it transports for a period of two years.

        Cost of Sales.    We enter into derivatives in our water solutions business to protect against the risk of a decline in the market price of the hydrocarbons we expect to recover when processing the wastewater. Our cost of sales for the three months ended September 30, 2014 was reduced by $12.7 million of net unrealized gains on derivatives and increased by $0.3 million of net realized losses on derivatives. Our cost of sales for the three months ended September 30, 2013 was increased by $0.2 million of net unrealized losses on derivatives and $0.9 million of net realized losses on derivatives. In the table above, the full impact of the change in derivative gains and losses during the three months ended September 30, 2014 as compared to the three months ended September 30, 2013 is reported in the "other" column, as it is not possible to attribute these gains and losses to individual water facilities.

        Operating Expenses.    Our water solutions segment incurred $29.0 million of operating expenses during the three months ended September 30, 2014, compared to $15.0 million of operating expenses during the three months ended September 30, 2013. Of this increase, $13.9 million related to the acquisitions subsequent to June 30, 2013, which includes a loss of $4.0 million related to the sale of our water transportation business. This increase was partially offset by losses on disposal of property, plant and equipment of $2.0 million during the three months ended September 30, 2013 as a result of property damage from lightning strikes at two of our facilities.

        General and Administrative Expenses.    Our water solutions segment incurred $0.8 million of general and administrative expenses during the three months ended September 30, 2014, compared to $1.1 million of general and administrative expenses during the three months ended September 30, 2013.

        Depreciation and Amortization Expense.    Our water solutions segment incurred $17.6 million of depreciation and amortization expense during the three months ended September 30, 2014, compared to $11.4 million of depreciation and amortization expense during the three months ended September 30, 2013. Of this increase, $5.7 million related to the acquisitions subsequent toJune 30, 2013, which included $0.5 million of amortization expense related to trade name intangible assets. Exclusive of the acquisitions subsequent to June 30, 2013, the increase is due in part to $0.6 million of amortization expense related to trade name intangible assets. During the year ended March 31, 2014, we ceased using certain trade names and began amortizing them as finite-lived defensive assets.

        Operating Income.    Our water solutions segment generated operating income of $14.8 million during the three months ended September 30, 2014, compared to operating income of $2.9 million

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during the three months ended September 30, 2013. This increase was due in part to an increase in the volume of wastewater processed, which was due to increased demand for existing facilities and to the development and acquisition of new facilities.

Liquids

        The following table summarizes the operating results of our liquids segment for the periods indicated:

 
  Three Months Ended
September 30,
   
 
 
  2014   2013   Change  
 
  (in thousands)
 

Revenues:

                   

Propane sales

  $ 240,433   $ 191,437   $ 48,996  

Other product sales

    306,625     308,606     (1,981 )

Other revenues

    6,814     9,250     (2,436 )
               

Total revenues(1)

    553,872     509,293     44,579  

Expenses:

                   

Cost of sales—propane

    230,729     184,565     46,164  

Cost of sales—other products

    293,262     292,142     1,120  

Cost of sales—other

    4,222     7,106     (2,884 )

Operating expenses

    9,183     6,800     2,383  

General and administrative expenses

    2,163     1,403     760  

Depreciation and amortization expense

    3,384     2,672     712  
               

Total expenses

    542,943     494,688     48,255  
               

Segment operating income

  $ 10,929   $ 14,605   $ (3,676 )
               
               

(1)
Revenues include $14.1 million and $24.4 million of intersegment sales during the three months ended September 30, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

        Revenues.    Our liquids segment generated $240.4 million of wholesale propane sales revenue during the three months ended September 30, 2014, selling 240.2 million gallons at an average price of $1.00 per gallon. During the three months ended September 30, 2013, our liquids segment generated $191.4 million of wholesale propane sales revenue, selling 183.4 million gallons at an average price of $1.04 per gallon. The increase in volume was due to higher market demand, due in part to cold weather conditions during the previous winter.

        Our liquids segment generated $306.6 million of other wholesale products sales revenue during the three months ended September 30, 2014, selling 197.5 million gallons at an average price of $1.55 per gallon. During the three months ended September 30, 2013, our liquids segment generated $308.6 million of other wholesale products sales revenue, selling 195.3 million gallons at an average price of $1.58 per gallon.

        Cost of Sales.    Our cost of wholesale propane sales was $230.7 million during the three months ended September 30, 2014, as we sold 240.2 million gallons at an average cost of $0.96 per gallon. Our cost of wholesale propane sales during the three months ended September 30, 2014 was increased by $1.9 million of net unrealized losses on derivatives. During the three months ended September 30, 2013, our cost of wholesale propane sales was $184.6 million, as we sold 183.4 million gallons at an average cost of $1.01 per gallon. Our cost of wholesale propane sales during the three months ended September 30, 2013 was increased by $3.6 million of net unrealized losses on derivatives.

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        Our cost of sales of other products was $293.3 million during the three months ended September 30, 2014, as we sold 197.5 million gallons at an average cost of $1.48 per gallon. Our cost of sales of other products during the three months ended September 30, 2014 was reduced by $2.2 million of net unrealized gains on derivatives. During the three months ended September 30, 2013, our cost of sales of other products was $292.1 million, as we sold 195.3 million gallons at an average cost of $1.50 per gallon. Our cost of sales of other products during the three months ended September 30, 2013 was reduced by $6.9 million of net unrealized gains on derivatives.

        Operating Expenses.    Our liquids segment incurred $9.2 million of operating expenses during the three months ended September 30, 2014, compared to $6.8 million of operating expenses during the three months ended September 30, 2013. This increase was due primarily to expanded operations.

        General and Administrative Expenses.    Our liquids segment incurred $2.2 million of general and administrative expenses during the three months ended September 30, 2014, compared to $1.4 million of general and administrative expenses during the three months ended September 30, 2013. This increase was due primarily to expanded operations.

        Depreciation and Amortization Expense.    Our liquids segment incurred $3.4 million of depreciation and amortization expense during the three months ended September 30, 2014, compared to $2.7 million of depreciation and amortization expense during the three months ended September 30, 2013.

        Operating Income.    Our liquids segment generated operating income of $10.9 million during the three months ended September 30, 2014, compared to operating income of $14.6 million during the three months ended September 30, 2013. Although sales volumes were higher during the three months ended September 30, 2014 than during the three months ended September 30, 2013, product margins were similar. This was due in part to the impact of unrealized gains on derivatives, which reduced cost of sales by $0.3 million during the three months ended September 30, 2014 and by $3.3 million during the three months ended September 30, 2013. Operating and general and administrative expenses were higher during the three months ended September 30, 2014 than during the three months ended September 30, 2013, due to expanded operations. The wholesale natural gas liquids business is weather-sensitive and subject to seasonal volume variations due to propane's primary use as a heating source and butane's use in gasoline blending, and sales prices and volumes are typically higher during the colder months of the year. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

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Retail Propane

        The following table summarizes the operating results of our retail propane segment for the periods indicated:

 
  Three Months Ended
September 30,
   
 
 
  2014   2013   Change  
 
  (in thousands)
 

Revenues:

                   

Propane sales

  $ 48,552   $ 40,651   $ 7,901  

Distillate sales

    11,530     10,562     968  

Other revenues

    8,276     8,198     78  
               

Total revenues

    68,358     59,411     8,947  

Expenses:

                   

Cost of sales—propane

    27,434     21,848     5,586  

Cost of sales—distillates

    9,840     9,265     575  

Cost of sales—other

    2,620     2,457     163  

Operating expenses

    21,205     20,997     208  

General and administrative expenses

    2,637     2,493     144  

Depreciation and amortization expense

    7,684     6,871     813  
               

Total expenses

    71,420     63,931     7,489  
               

Segment operating loss

  $ (3,062 ) $ (4,520 ) $ 1,458  
               
               

        Revenues.    Our retail propane segment generated revenue of $48.6 million from propane sales during the three months ended September 30, 2014, selling 23.6 million gallons at an average price of $2.06 per gallon. During the three months ended September 30, 2013, our retail propane segment generated $40.7 million of revenue from propane sales, selling 20.6 million gallons at an average price of $1.97 per gallon. The increase in average sales prices during the three months ended September 30, 2014 compared to the three months ended September 30, 2013 was due primarily to higher market demand as a result of cold weather conditions during the recent winter.

        Our retail propane segment generated revenue of $11.5 million from distillate sales during the three months ended September 30, 2014, selling 3.4 million gallons at an average price of $3.36 per gallon. During the three months ended September 30, 2013, our retail propane segment generated $10.6 million of revenue from distillate sales, selling 3.1 million gallons at an average price of $3.44 per gallon.

        Cost of Sales.    Our cost of retail propane sales was $27.4 million during the three months ended September 30, 2014, as we sold 23.6 million gallons at an average cost of $1.16 per gallon. During the three months ended September 30, 2013, our cost of retail propane sales was $21.8 million, as we sold 20.6 million gallons at an average cost of $1.06 per gallon.

        Our cost of distillate sales was $9.8 million during the three months ended September 30, 2014, as we sold 3.4 million gallons at an average cost of $2.87 per gallon. During the three months ended September 30, 2013, our cost of distillate sales was $9.3 million, as we sold 3.1 million gallons at an average cost of $3.02 per gallon.

        Operating Expenses.    Our retail propane segment incurred $21.2 million of operating expenses during the three months ended September 30, 2014, compared to $21.0 million of operating expenses during the three months ended September 30, 2013.

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        General and Administrative Expenses.    Our retail propane segment incurred $2.6 million of general and administrative expenses during the three months ended September 30, 2014, compared to $2.5 million of general and administrative expenses during the three months ended September 30, 2013.

        Depreciation and Amortization Expense.    Our retail propane segment incurred $7.7 million of depreciation and amortization expense during the three months ended September 30, 2014, compared to $6.9 million of depreciation and amortization expense during the three months ended September 30, 2013.

        Operating Loss.    Our retail propane segment generated an operating loss of $3.1 million during the three months ended September 30, 2014, compared to an operating loss of $4.5 million during the three months ended September 30, 2013. The decrease in operating loss was due primarily due to an increase in propane sales volumes. Demand was high during the three months ended September 30, 2014, as customers sought to replenish their supplies of natural gas liquids that had been depleted during the winter. The retail propane business is weather-sensitive and subject to seasonal volume variations due to propane's primary use as a heating source in residential and commercial buildings and for agricultural purposes. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

Refined Products and Renewables

        The following table summarizes the operating results of our refined products and renewables segment during the three months ended September 30, 2014 (in thousands). Our refined products and renewables segment began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne.

Revenues:

       

Refined products sales

  $ 2,489,795  

Renewables sales(1)

    117,425  
       

Total revenues

    2,607,220  

Expenses:

       

Cost of sales—refined products

    2,435,868  

Cost of sales—renewables(1)

    114,983  

Operating expenses

    29,838  

General and administrative expenses

    5,792  

Depreciation and amortization expense

    11,917  
       

Total expenses

    2,598,398  
       

Segment operating income

  $ 8,822  
       
       

(1)
Revenues and cost of sales include $4.9 million and $2.0 million, respectively, associated with freely tradable Renewable Identification Numbers ("RINs") with no corresponding sales volume during the three months ended September 30, 2014.

        Revenues.    Our refined products and renewables segment generated $2.5 billion of refined products sales revenue during the three months ended September 30, 2014, selling 890.1 million gallons at an average price of $2.80 per gallon.

        Our refined products and renewables segment generated $112.5 million of renewables sales revenue (excluding freely tradable RINS) during the three months ended September 30, 2014, selling 51.6 million gallons at an average price of $2.18 per gallon.

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        Cost of Sales.    Our cost of refined products sales was $2.4 billion during the three months ended September 30, 2014, as we sold 890.1 million gallons at an average cost of $2.74 per gallon.

        Our cost of renewables sales was $113.0 million (excluding freely tradable RINS) during the three months ended September 30, 2014, as we sold 51.6 million gallons at an average cost of $2.19 per gallon. We use a weighted-average inventory costing method for our ethanol inventory. During periods of declining prices, our margins are reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher.

        Operating Expenses.    Our refined products and renewables segment incurred $29.8 million of operating expenses during the three months ended September 30, 2014.

        General and Administrative Expenses.    Our refined products and renewables segment incurred $5.8 million of general and administrative expenses during the three months ended September 30, 2014. General and administrative expenses during the three months ended September 30, 2014 were increased by $0.1 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. General and administrative expenses during the three months ended September 30, 2014 were also increased by $1.5 million of compensation expense related to termination benefits for certain TransMontaigne employees.

        Depreciation and Amortization Expense.    Our refined products and renewables segment incurred $11.9 million of depreciation and amortization expense during the three months ended September 30, 2014.

        Operating Income.    Our refined products and renewables segment generated operating income of $8.8 million during the three months ended September 30, 2014. The adverse impact resulting from declining refined products prices during the quarter was mitigated by gains on hedges entered into to protect against the risk of declines in inventory prices.

Corporate and Other

        The operating loss within "corporate and other" includes the following components:

 
  Three Months Ended
September 30,
   
 
 
  2014   2013   Change  
 
  (in thousands)
 

Equity-based compensation expense

  $ (13,745 ) $ (3,217 ) $ (10,528 )

Acquisition expenses

    (3,230 )   (785 )   (2,445 )

Other corporate expenses

    (6,774 )   (4,935 )   (1,839 )
               

  $ (23,749 ) $ (8,937 ) $ (14,812 )
               
               

        The increase in equity-based compensation expense is due primarily to $10.5 million of expense associated with restricted units granted in July 2014 to certain employees as a discretionary bonus that vested in September 2014.

        Acquisition expenses during the three months ended September 30, 2014 related primarily to the acquisition of TransMontaigne.

        The increase in other corporate expenses is due primarily to increases in compensation expense, due to the addition of new corporate employees to provide general and administrative services in support of the growth of our business.

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Segment Operating Results for the Six Months Ended September 30, 2014 and 2013

Items Impacting the Comparability of Our Financial Results

        Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of Crescent and Cierra Marine in July 2013, Gavilon Energy in December 2013 and TransMontaigne in July 2014. We expanded our water solutions business through several acquisitions of water disposal and transportation businesses, including Big Lake in July 2013, OWL in August 2013, Coastal in September 2013, and other water disposal facilities subsequent to September 30, 2013. Our refined products and renewables businesses began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne. The results of operations of our liquids and retail propane segments are impacted by seasonality, primarily due to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our sales volumes and revenues. For these and other reasons, our results of operations for the six months ended September 30, 2014 are not necessarily indicative of the results to be expected for the full fiscal year.

Volumes

        The following table summarizes the volume of product sold and water delivered during the six months ended September 30, 2014 and 2013. Volumes shown in the following table include intersegment sales.

 
  Six Months Ended
September 30,
   
 
Segment
  2014   2013   Change  
 
  (in thousands)
 

Crude oil logistics

                   

Crude oil sold (barrels)

    40,806     18,535     22,271  

Water solutions

   
 
   
 
   
 
 

Water delivered (barrels)

    51,804     26,498     25,306  

Liquids

   
 
   
 
   
 
 

Propane sold (gallons)

    423,992     310,834     113,158  

Other products sold (gallons)

    384,235     373,722     10,513  

Retail propane

   
 
   
 
   
 
 

Propane sold (gallons)

    47,142     43,992     3,150  

Distillates sold (gallons)

    8,712     8,176     536  

Refined products and renewables

   
 
   
 
   
 
 

Refined products sold (gallons)

    1,221,949         1,221,949  

Renewable products sold (gallons)

    104,591         104,591  

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Operating Income (Loss) by Segment

        Our operating income (loss) by segment is as follows:

 
  Six Months Ended
September 30,
   
 
Segment
  2014   2013   Change  
 
  (in thousands)
 

Crude oil logistics

  $ 1,501   $ 12,493   $ (10,992 )

Water solutions

    13,885     5,956     7,929  

Liquids

    10,016     12,490     (2,474 )

Retail propane

    (4,648 )   (6,024 )   1,376  

Refined products and renewables

    7,567         7,567  

Corporate and other

    (41,106 )   (22,312 )   (18,794 )
               

Operating income (loss)

  $ (12,785 ) $ 2,603   $ (15,388 )
               
               

Crude Oil Logistics

        The following table summarizes the operating results of our crude oil logistics segment for the periods indicated:

 
  Six Months Ended
September 30,
   
 
 
  2014   2013   Change  
 
  (in thousands)
 

Revenues:

                   

Crude oil sales

  $ 4,035,061   $ 1,941,595   $ 2,093,466  

Crude oil transportation and other

    25,196     19,729     5,467  
               

Total revenues(1)

    4,060,257     1,961,324     2,098,933  

Expenses:

                   

Cost of sales

    4,001,158     1,917,876     2,083,282  

Operating expenses

    28,417     21,175     7,242  

General and administrative expenses

    10,210     1,766     8,444  

Depreciation and amortization expense

    18,971     8,014     10,957  
               

Total expenses

    4,058,756     1,948,831     2,109,925  
               

Segment operating income

  $ 1,501   $ 12,493   $ (10,992 )
               
               

(1)
Revenues include $19.8 million and $16.5 million of intersegment sales during the six months ended September 30, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

        Revenues.    Our crude oil logistics segment generated $4.0 billion of revenue from crude oil sales during the six months ended September 30, 2014, selling 40.8 million barrels at an average price of $98.88 per barrel. During the six months ended September 30, 2013, our crude oil logistics segment generated $1.9 billion of revenue from crude oil sales, selling 18.5 million barrels at an average price of $104.75 per barrel.

        Crude oil transportation and other revenues of our crude oil logistics segment were $25.2 million during the six months ended September 30, 2014, compared to $19.7 million of crude oil transportation and other revenues during the six months ended September 30, 2013. This increase was due primarily to the Crescent and Cierra Marine acquisition in July 2013 and the Gavilon acquisition in December 2013.

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        Cost of Sales.    Our cost of crude oil sold was $4.0 billion during the six months ended September 30, 2014, as we sold 40.8 million barrels at an average cost of $98.05 per barrel. Our cost of sales during the six months ended September 30, 2014 was reduced by $3.1 million of net unrealized gains on derivatives. During the six months ended September 30, 2013, our cost of crude oil sold was $1.9 billion, as we sold 18.5 million barrels at an average cost of $103.47 per barrel. Our cost of sales during the six months ended September 30, 2013 was reduced by $1.5 million of net unrealized gains on derivatives.

        The most significant drivers of the increase in our volumes, revenues, and cost of sales were the acquisition of Gavilon Energy in December 2013 and TransMontaigne in July 2014. Spreads between the price of crude oil in different markets narrowed during the six months ended September 30, 2013 and remained narrow, which reduced our opportunity to generate increased margins by transporting crude oil from lower-price markets to higher-price markets.

        Operating Expenses.    Our crude oil logistics segment incurred $28.4 million of operating expenses during the six months ended September 30, 2014, compared to $21.2 million of operating expenses during the six months ended September 30, 2013. This increase was primarily due to the Gavilon acquisition in December 2013.

        General and Administrative Expenses.    Our crude oil logistics segment incurred $10.2 million of general and administrative expenses during the six months ended September 30, 2014, compared to $1.8 million of general and administrative expenses during the six months ended September 30, 2013. This increase was due to the acquisitions of Gavilon Energy in December 2013 and TransMontaigne in July 2014. General and administrative expenses during the six months ended September 30, 2014 were increased by $4.3 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. General and administrative expenses during the six months ended September 30, 2014 were also increased by $1.2 million of compensation expense related to termination benefits for certain TransMontaigne employees.

        Depreciation and Amortization Expense.    Our crude oil logistics segment incurred $19.0 million of depreciation and amortization expense during the six months ended September 30, 2014, compared to $8.0 million of depreciation and amortization expense during the six months ended September 30, 2013. This increase was primarily due to acquisitions and capital expansions.

        Operating Income.    Our crude oil logistics segment generated operating income of $1.5 million during the six months ended September 30, 2014, compared to operating income of $12.5 million during the six months ended September 30, 2013. Operating income during the three months ended September 30, 2014 was increased by $3.1 million of net unrealized gains on derivatives. Operating income during the three months ended September 30, 2013 was increased by $1.5 million of net unrealized gains on derivatives. Spreads between the price of crude oil in different markets narrowed during the six months ended September 30, 2013 and remained narrow, which reduced our opportunity to generate increased margins by transporting crude oil from lower-price markets to higher-price markets.

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Water Solutions

        The following table summarizes the operating results of our water solutions segment for the periods indicated:

 
  Six Months Ended
September 30,
  Change  
 
  2014   2013   Acquisitions(1)   Other  
 
  (in thousands)
 

Revenues:

                         

Water treatment and disposal

  $ 89,288   $ 47,511   $ 28,627   $ 13,150  

Water transportation

    10,745     7,192     6,954     (3,401 )
                   

Total revenues

    100,033     54,703     35,581     9,749  

Expenses:

                         

Cost of sales

    1,134     4,365     4,984     (8,215 )

Operating expenses

    48,748     24,010     23,141     1,597  

General and administrative expenses

    1,601     1,578     199     (176 )

Depreciation and amortization expense

    34,665     18,794     15,348     523  
                   

Total expenses

    86,148     48,747     43,672     (6,271 )
                   

Segment operating income

  $ 13,885   $ 5,956   $ (8,091 ) $ 16,020  
                   
                   

(1)
Represents the change in revenues and expenses attributable to acquisitions subsequent to March 31, 2013. The cost of sales amount shown in this column does not include derivative gains and losses, as these cannot be attributed to specific facilities.

        Revenues.    The acquisitions subsequent to March 31, 2013 generated $35.6 million of treatment and disposal revenue during the six months ended September 30, 2014, taking delivery of 22.9 million barrels of wastewater at an average revenue of $1.56 per barrel. Exclusive of the acquisitions subsequent to March 31, 2013, our water solutions segment generated $53.7 million of treatment and disposal revenue during the six months ended September 30, 2014, taking delivery of 28.9 million barrels of wastewater at an average revenue of $1.85 per barrel. The acquisitions subsequent to March 31, 2013 generated $7.0 million of treatment and disposal revenue during the six months ended September 30, 2013, taking delivery of 5.1 million barrels of wastewater at an average revenue of $1.37per barrel. Exclusive of the acquisitions subsequent to March 31, 2013, our water solutions segment generated $40.5 million of treatment and disposal revenue during the six months ended September 30, 2014, taking delivery of 21.4 million barrels of wastewater at an average revenue of $1.89 per barrel. The primary reasons for the increase in revenues and water delivered were acquisitions made subsequent to March 31, 2013, including our acquisitions of Big Lake, OWL and Coastal, and to an increase in water volumes processed due to higher demand from customers.

        Water transportation revenues increased by $3.6 million during the six months ended September 30, 2014 compared to the six months ended September 30, 2013, due primarily to the acquisition of OWL. During September 2014, we sold our water transportation business in order to focus our efforts on water processing. As part of this transaction, the buyer of the transportation business committed to deliver to our facilities substantially all of the water it transports for a period of two years.

        Cost of Sales.    We enter into derivatives in our water solutions business to protect against the risk of a decline in the market price of the hydrocarbons we expect to recover when processing the wastewater. Our cost of sales for the six months ended September 30, 2014 was reduced by $6.6 million of net unrealized gains on derivatives and increased by $1.5 million of net realized losses on derivatives. Our cost of sales for the six months ended September 30, 2013 was reduced by $0.3 million of net

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unrealized gains on derivatives and increased by $1.1 million of net realized losses on derivatives. In the table above, the full impact of the change in derivative gains and losses during the six months ended September 30, 2014 as compared to the six months ended September 30, 2013 is reported in the "other" column, as it is not possible to attribute these gains and losses to individual water facilities.

        Operating Expenses.    Our water solutions segment incurred $48.7 million of operating expenses during the six months ended September 30, 2014, compared to $24.0 million of operating expenses during the six months ended September 30, 2013. Of this increase, $23.1 million related to the acquisitions subsequent to March 31, 2013, which includes a loss of $4.0 million related to the sale of our water transportation business. This increase was partially offset by losses on disposal of property, plant and equipment of $2.0 million during the six months ended September 30, 2013 as a result of property damage from lightning strikes at two of our facilities.

        General and Administrative Expenses.    Our water solutions segment incurred $1.6 million of general and administrative expenses during the six months ended September 30, 2014 and the six months ended September 30, 2013.

        Depreciation and Amortization Expense.    Our water solutions segment incurred $34.7 million of depreciation and amortization expense during the six months ended September 30, 2014, compared to $18.8 million of depreciation and amortization expense during the six months ended September 30, 2013. Of this increase, $15.3 million related to the acquisitions subsequent to March 31, 2013, which included $1.0 million of amortization expense related to trade name intangible assets. Exclusive of the acquisitions subsequent to March 31, 2013, the increase is due in part to $1.2 million of amortization expense related to trade name intangible assets. During the year ended March 31, 2014, we ceased using certain trade names and began amortizing them as finite-lived defensive assets.

        Operating Income.    Our water solutions segment generated operating income of $13.9 million during the six months ended September 30, 2014, compared to operating income of $6.0 million during the six months ended September 30, 2013. This increase was due in part to an increase in the volume of wastewater processed, which was due to increased demand for existing facilities and to the development and acquisition of new facilities.

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Liquids

        The following table summarizes the operating results of our liquids segment for the periods indicated:

 
  Six Months Ended
September 30,
   
 
 
  2014   2013   Change  
 
  (in thousands)
 

Revenues:

                   

Propane sales

  $ 462,879   $ 315,274   $ 147,605  

Other product sales

    594,984     558,459     36,525  

Other revenues

    12,530     18,114     (5,584 )
               

Total revenues(1)

    1,070,393     891,847     178,546  

Expenses:

   
 
   
 
   
 
 

Cost of sales—propane

    449,636     302,108     147,528  

Cost of sales—other products

    574,524     541,077     33,447  

Cost of sales—other

    7,403     12,474     (5,071 )

Operating expenses

    18,248     15,532     2,716  

General and administrative expenses

    3,981     2,790     1,191  

Depreciation and amortization expense

    6,585     5,376     1,209  
               

Total expenses

    1,060,377     879,357     181,020  
               

Segment operating income

  $ 10,016   $ 12,490   $ (2,474 )
               
               

(1)
Revenues include $55.5 million and $46.0 million of intersegment sales during the six months ended September 30, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

        Revenues.    Our liquids segment generated $462.9 million of wholesale propane sales revenue during the six months ended September 30, 2014, selling 424.0 million gallons at an average price of $1.09 per gallon. During the six months ended September 30, 2013, our liquids segment generated $315.3 million of wholesale propane sales revenue, selling 310.8 million gallons at an average price of $1.01 per gallon. The increase in volume was due to higher market demand, due in part to cold weather conditions during the previous winter.

        Our liquids segment generated $595.0 million of other wholesale products sales revenue during the six months ended September 30, 2014, selling 384.2 million gallons at an average price of $1.55 per gallon. During the six months ended September 30, 2013, our liquids segment generated $558.5 million of other wholesale products sales revenue, selling 373.7 million gallons at an average price of $1.49 per gallon.

        Cost of Sales.    Our cost of wholesale propane sales was $449.6 million during the six months ended September 30, 2014, as we sold 424.0 million gallons at an average cost of $1.06 per gallon. Our cost of wholesale propane sales during the six months ended September 30, 2014 was increased by $1.7 million of net unrealized losses on derivatives. During the six months ended September 30, 2013, our cost of wholesale propane sales was $302.1 million, as we sold 310.8 million gallons at an average cost of $0.97 per gallon. Our cost of wholesale propane sales during the six months ended September 30, 2013 was increased by $5.2 million of net unrealized losses on derivatives.

        Product margins per gallon of propane sold were lower during the six months ended September 30, 2014 than during the six months ended September 30, 2013. Propane prices were high during the recent winter due to cold weather conditions, and prices declined during February and March 2014. We use a

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weighted-average inventory costing method for our wholesale propane inventory, with the costing pools segregated based on the location of the inventory. During periods of declining prices, our margins are reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher.

        One of our business strategies is to purchase and store inventory during the warmer months for sale during the winter months. We seek to lock in a margin on inventory held in storage through back-to-back purchases and sales, fixed-price forward sale commitments, and financial derivatives. We also have contracts whereby we have committed to purchase ratable volumes each month at index prices. We seek to manage the price risk associated with these contracts primarily by selling the inventory immediately after it is received. When we sell product, we record the cost of the sale at the average cost of all inventory at that location, which may include inventory stored for sale in the future. During periods of rising prices, this can result in greater margins on these sales. During periods of falling prices, this can result in negative margins on these sales.

        Our cost of sales of other products was $574.5 million during the six months ended September 30, 2014, as we sold 384.2 million gallons at an average cost of $1.50 per gallon. Our cost of sales of other products during the six months ended September 30, 2014 was reduced by $0.8 million of net unrealized gains on derivatives. During the six months ended September 30, 2013, our cost of sales of other products was $541.1 million, as we sold 373.7 million gallons at an average cost of $1.45 per gallon. Our cost of sales of other products during the six months ended September 30, 2013 was increased by $0.3 million of net unrealized losses on derivatives.

        Operating Expenses.    Our liquids segment incurred $18.2 million of operating expenses during the six months ended September 30, 2014, compared to $15.5 million of operating expenses during the six months ended September 30, 2013. This increase was due primarily to expanded operations.

        General and Administrative Expenses.    Our liquids segment incurred $4.0 million of general and administrative expenses during the six months ended September 30, 2014, compared to $2.8 million of general and administrative expenses during the six months ended September 30, 2013. This increase was due primarily to expanded operations.

        Depreciation and Amortization Expense.    Our liquids segment incurred $6.6 million of depreciation and amortization expense during the six months ended September 30, 2014, compared to $5.4 million of depreciation and amortization expense during the six months ended September 30, 2013.

        Operating Income.    Our liquids segment generated operating income of $10.0 million during the six months ended September 30, 2014, compared to operating income of $12.5 million during the six months ended September 30, 2013. The wholesale natural gas liquids business is weather-sensitive and subject to seasonal volume variations due to propane's primary use as a heating source and butane's use in gasoline blending, and sales prices and volumes are typically higher during the colder months of the year. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

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Retail Propane

        The following table summarizes the operating results of our retail propane segment for the periods indicated:

 
  Six Months Ended
September 30,
   
 
 
  2014   2013   Change  
 
  (in thousands)
 

Revenues:

                   

Propane sales

  $ 100,578   $ 87,342   $ 13,236  

Distillate sales

    30,225     28,431     1,794  

Other revenues

    15,457     15,898     (441 )
               

Total revenues

    146,260     131,671     14,589  

Expenses:

                   

Cost of sales—propane

    56,721     47,027     9,694  

Cost of sales—distillates

    25,876     24,509     1,367  

Cost of sales—other

    4,821     5,100     (279 )

Operating expenses

    42,687     41,839     848  

General and administrative expenses

    5,548     5,109     439  

Depreciation and amortization expense

    15,255     14,111     1,144  
               

Total expenses

    150,908     137,695     13,213  
               

Segment operating loss

  $ (4,648 ) $ (6,024 ) $ 1,376  
               
               

        Revenues.    Our retail propane segment generated revenue of $100.6 million from propane sales during the six months ended September 30, 2014, selling 47.1 million gallons at an average price of $2.13 per gallon. During the six months ended September 30, 2013, our retail propane segment generated $87.3 million of revenue from propane sales, selling 44.0 million gallons at an average price of $1.99 per gallon. The increase in volumes and average sales prices during the six months ended September 30, 2014 compared to the six months ended September 30, 2013 was due primarily to higher market demand as a result of cold weather conditions during the recent winter.

        Our retail propane segment generated revenue of $30.2 million from distillate sales during the six months ended September 30, 2014, selling 8.7 million gallons at an average price of $3.47 per gallon. During the six months ended September 30, 2013, our retail propane segment generated $28.4 million of revenue from distillate sales, selling 8.2 million gallons at an average price of $3.48 per gallon.

        Cost of Sales.    Our cost of retail propane sales was $56.7 million during the six months ended September 30, 2014, as we sold 47.1 million gallons at an average cost of $1.20 per gallon. During the six months ended September 30, 2013, our cost of retail propane sales was $47.0 million, as we sold 44.0 million gallons at an average cost of $1.07 per gallon.

        Our cost of distillate sales was $25.9 million during the six months ended September 30, 2014, as we sold 8.7 million gallons at an average cost of $2.97 per gallon. During the six months ended September 30, 2013, our cost of distillate sales was $24.5 million, as we sold 8.2 million gallons at an average cost of $3.00 per gallon.

        Operating Expenses.    Our retail propane segment incurred $42.7 million of operating expenses during the six months ended September 30, 2014, compared to $41.8 million of operating expenses during the six months ended September 30, 2013.

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        General and Administrative Expenses.    Our retail propane segment incurred $5.5 million of general and administrative expenses during the six months ended September 30, 2014, compared to $5.1 million of general and administrative expenses during the six months ended September 30, 2013.

        Depreciation and Amortization Expense.    Our retail propane segment incurred $15.3 million of depreciation and amortization expense during the six months ended September 30, 2014, compared to $14.1 million of depreciation and amortization expense during the six months ended September 30, 2013.

        Operating Loss.    Our retail propane segment generated an operating loss of $4.6 million during the six months ended September 30, 2014, compared to an operating loss of $6.0 million during the six months ended September 30, 2013. The decrease in operating loss was due primarily to an increase in propane sales volumes. Demand was high during the six months ended September 30, 2014, as customers sought to replenish their supplies of natural gas liquids that had been depleted during the winter. The retail propane business is weather-sensitive and subject to seasonal volume variations due to propane's primary use as a heating source in residential and commercial buildings and for agricultural purposes. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

Refined Products and Renewables

        The following table summarizes the operating results of our refined products and renewables segment during the six months ended September 30, 2014 (in thousands). Our refined products and renewables segment began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne.

Revenues:

       

Refined products sales

  $ 3,476,018  

Renewables sales(1)

    248,699  
       

Total revenues

    3,724,717  

Expenses:

       

Cost of sales—refined products

    3,418,880  

Cost of sales—renewables(1)

    246,284  

Operating expenses

    31,462  

General and administrative expenses

    7,763  

Depreciation and amortization expense

    12,761  
       

Total expenses

    3,717,150  
       

Segment operating income

  $ 7,567  
       
       

(1)
Revenues and cost of sales include $6.7 million and $4.4 million, respectively, associated with freely tradable RINs with no corresponding sales volume during the six months ended September 30, 2014.

        Revenues.    Our refined products and renewables segment generated $3.5 billion of refined products sales revenue during the six months ended September 30, 2014, selling 1.2 billion gallons at an average price of $2.84 per gallon.

        Our refined products and renewables segment generated $242.0 (excluding freely tradable RINs) million of renewables sales revenue during the six months ended September 30, 2014, selling 104.6 million gallons at an average price of $2.31 per gallon.

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        Cost of Sales.    Our cost of refined products sales was $3.4 billion during the six months ended September 30, 2014, as we sold 1.2 billion gallons at an average cost of $2.80 per gallon.

        Our cost of renewables sales was $241.9 (excluding freely tradable RINs) million during the six months ended September 30, 2014, as we sold 104.6 million gallons at an average cost of $2.31 per gallon. We use a weighted-average inventory costing method for our ethanol inventory. During periods of declining prices, our margins are reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher.

        Operating Expenses.    Our refined products and renewables segment incurred $31.5 million of operating expenses during the six months ended September 30, 2014.

        General and Administrative Expenses.    Our refined products and renewables segment incurred $7.8 million of general and administrative expenses during thesix months ended September 30, 2014. General and administrative expenses during the six months ended September 30, 2014 were increased by $0.4 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. General and administrative expenses during the six months ended September 30, 2014 were also increased by $1.5 million of compensation expense related to termination benefits for certain TransMontaigne employees.

        Depreciation and Amortization Expense.    Our refined products and renewables segment incurred $12.8 million of depreciation and amortization expense during the six months ended September 30, 2014.

        Operating Income.    Our refined products and renewables segment generated operating income of $7.6 million during the six months ended September 30, 2014. The adverse impact resulting from declining refined products prices during the quarter was mitigated by gains on hedges entered into to protect against the risk of declines in inventory prices.

Corporate and Other

        The operating loss within "corporate and other" includes the following components:

 
  Six Months Ended
September 30,
   
 
 
  2014   2013   Change  
 
  (in thousands)
 

Equity-based compensation expense

  $ (21,659 ) $ (10,292 ) $ (11,367 )

Acquisition expenses

    (4,328 )   (1,368 )   (2,960 )

Other corporate expenses

    (15,119 )   (10,652 )   (4,467 )
               

  $ (41,106 ) $ (22,312 ) $ (18,794 )
               
               

        The increase in equity-based compensation expense is due primarily to $10.5 million of expense associated with restricted units granted in July 2014 to certain employees as a discretionary bonus that vested in September 2014.

        Acquisition expenses during the six months ended September 30, 2014 related primarily to the acquisition of TransMontaigne.

        The increase in other corporate expenses is due primarily to increases in compensation expense, due to the addition of new corporate employees to provide general and administrative services in support of the growth of our business.

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        Operating loss during the six months ended September 30, 2014 was increased by $0.4 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. This amount is reported within "other corporate expenses" in the table above.

Interest Expense

        The largest component of interest expense during the three months and six months ended September 30, 2014 and 2013 has been interest on our Revolving Credit Facility, the 2019 Notes, the 2021 Notes, the 2022 Notes, and the TLP Credit Facility (each as hereinafter defined). See Note 7 to our unaudited condensed consolidated financial statements included elsewhere in this prospectus for additional information on our long-term debt. The change in interest expense during the periods presented is due primarily to fluctuations in the average outstanding debt balance and the applicable interest rates, as summarized below:

 
  Revolving Credit
Facility
  2019 Notes   2021 Notes   2022 Notes   TLP Credit Facility  
 
  Average
Balance
Outstanding
(in thousands)
  Average
Interest
Rate
  Average
Balance
Outstanding
(in thousands)
  Interest
Rate
  Average
Balance
Outstanding
(in thousands)
  Interest
Rate
  Average
Balance
Outstanding
(in thousands)
  Interest
Rate
  Average
Balance
Outstanding
(in thousands)
  Average
Interest
Rate
 

Three Months Ended September 30,

                                                             

2014

  $ 1,026,011     2.48 % $ 360,870     5.13 % $ 450,000     6.88 % $ 250,000     6.65 % $ 246,750     2.70 %

2013

    572,353     3.63 %                   250,000     6.65 %        

Six Months Ended September 30,

   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

2014

  $ 987,224     2.38 % $ 181,424     5.13 % $ 450,000     6.88 % $ 250,000     6.65 % $ 246,750     2.70 %

2013

    521,202     3.65 %                   250,000     6.65 %        

        Interest expense also includes amortization of debt issuance costs, letter of credit fees, interest on equipment financing notes, and accretion of interest on noninterest bearing debt obligations assumed in business combinations.

        The increased level of debt outstanding during the three months and six months ended September 30, 2014 is due primarily to borrowings to finance acquisitions.

Income Tax Provision

        We qualify as a partnership for income tax purposes. As such, we generally do not pay United States federal income tax. Rather, each owner reports his or her share of our income or loss on his or her individual tax return.

        We have certain taxable corporate subsidiaries in the United States and in Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales. We utilize the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.

        Income tax benefit was $1.9 million during the three months ended September 30, 2014, compared to $0.2 million of income tax expense during the three months ended September 30, 2013. The increase in the income tax benefit was primarily due to the July 2014 acquisition of TransMontaigne, as TransMontaigne is subject to United States federal and state income taxes.

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        Income tax benefit was $0.9 million during the six months ended September 30, 2014, compared to $0.2 million of an income tax benefit during the six months ended September 30, 2013. The increase in the income tax benefit was primarily due to the July 2014 acquisition of TransMontaigne, as TransMontaigne is subject to United States federal and state income taxes.

Noncontrolling Interests

        We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our condensed consolidated statements of operations represents the other owners' share of the net income of these entities.

        Net income attributable to noncontrolling interests was $3.3 million during the three months ended September 30, 2014, compared to less than $0.1 million of net income attributable to noncontrolling interests during the three months ended September 30, 2013. The increase was primarily due to the July 2014 acquisition of TransMontaigne, in which we acquired the general partner interest and a 19.7% limited partner interest in TLP.

        Net income attributable to noncontrolling interests was $3.4 million during the six months ended September 30, 2014, compared to $0.1 million of net income attributable to noncontrolling interests during the six months ended September 30, 2013. The increase was primarily due to the July 2014 acquisition of TransMontaigne, in which we acquired the general partner interest and a 19.7% limited partner interest in TLP.

Seasonality

        Seasonality impacts our liquids and retail propane segments. A large portion of our retail propane business is in the residential market where propane is used primarily for home heating purposes. Consequently, for these two segments, revenues, operating profits and operating cash flows are generated mostly in the third and fourth quarters of each fiscal year. See "—Liquidity, Sources of Capital and Capital Resource Activities—Cash Flows."

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Consolidated Results of Operations—Year ended March 31, 2014

        The following table summarizes our historical consolidated statements of operations for the years ended March 31, 2014, 2013, and 2012:

 
  Year Ended March 31,  
 
  2014   2013   2012  
 
  (in thousands)
 

Total revenues

  $ 9,699,274   $ 4,417,767   $ 1,310,473  

Total cost of sales

    9,132,699     4,039,110     1,217,023  

Operating and general and administrative expenses

    339,256     222,497     63,309  

Depreciation and amortization

    120,754     68,853     15,111  
               

Operating income

    106,565     87,307     15,030  

Earnings of unconsolidated entities

    1,898          

Interest expense

    (58,854 )   (32,994 )   (7,620 )

Loss on early extinguishment of debt

        (5,769 )    

Other, net

    86     1,521     1,055  
               

Income before income taxes

    49,695     50,065     8,465  

Income tax provision

    (937 )   (1,875 )   (601 )
               

Net income

    48,758     48,190     7,864  

Net (income) loss attributable to noncontrolling interests

    (1,103 )   (250 )   12  
               

Net income attributable to parent equity

  $ 47,655   $ 47,940   $ 7,876  
               
               

        See the detailed discussion of revenues, cost of sales, operating expenses, general and administrative expenses, depreciation and amortization expense and operating income by segment below.

Interest Expense

        See Note 8 to our audited consolidated financial statements included elsewhere in this prospectus for additional information on our long-term debt. The change in interest expense during the periods presented is due primarily to fluctuations in the average outstanding debt balance, and in the applicable interest rates, as summarized below:

 
  Revolving Credit
Facilities
  Senior Notes   Unsecured Notes  
Year Ended:
  Average
Balance
Outstanding
(in thousands)
  Average
Interest
Rate
  Average
Balance
Outstanding
(in thousands)
  Interest
Rate
  Average
Balance
Outstanding
(in thousands)
  Interest
Rate
 

March 31, 2014

  $ 588,375     3.04 % $ 250,000     6.65 % $ 205,890     6.88 %

March 31, 2013

    405,114     3.56 %   195,890     6.65 %        

March 31, 2012

    125,859     4.48 %                

        Interest expense also includes amortization of debt issuance costs, which represented $5.7 million of expense during the year ended March 31, 2014, $3.4 million of expense during the year ended March 31, 2013, and $1.3 million of expense during the year ended March 31, 2012. Interest expense also includes letter of credit fees, interest on equipment financing notes, and accretion of interest on non-interest bearing debt obligations assumed in business combinations.

        On June 19, 2012, we made a principal payment of $306.8 million to retire our previous revolving credit facility. Upon retirement of this facility, we wrote off the portion of the debt issuance cost asset

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that had not yet been amortized. This expense is reported as "Loss on early extinguishment of debt" in our consolidated statement of operations for the year ended March 31, 2013.

        The increased levels of debt outstanding during the periods from fiscal 2012 through fiscal 2014 are due primarily to borrowings to finance acquisitions.

Income Tax Provision

        We believe that we qualify as a partnership for income tax purposes. As such, we generally do not pay United States federal income tax. Rather, each owner reports his or her share of our income or loss on his or her individual tax return.

        We have certain taxable corporate subsidiaries in the United States and Canada. In addition, our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales.

Noncontrolling Interests

        We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our consolidated statements of operations represents the other owners' share of the net income of these entities.

Segment Operating Results

Items Impacting the Comparability of Our Financial Results

        Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of High Sierra in June 2012, Pecos in November 2012, Third Coast in December 2012, Crescent in July 2013, and Gavilon Energy in December 2013. We expanded our water solutions business through several acquisitions of water disposal and transportation businesses, including High Sierra in June 2012, Big Lake in July 2013, OWL in August 2013, and Coastal in September 2013. We expanded our liquids business through the acquisitions of SemStream in October 2011 and High Sierra in June 2012. We expanded our retail propane operations through the acquisitions of Osterman in October 2011, Pacer in January 2012, North American in February 2012, and Downeast in May 2012. Our refined products and renewables businesses began with our December 2013 acquisition of Gavilon Energy.

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Volumes

        The following table summarizes the volume of product sold and water delivered for the years ended March 31, 2014 and 2013. Volumes shown in the table below for our liquids segment include sales to our retail propane segment.

 
  Year Ended March 31,    
 
Segment
  2014   2013   Change  
 
  (in thousands)
 

Crude oil logistics

                   

Crude oil sold (barrels)

    46,107     24,373     21,734  

Water solutions

   
 
   
 
   
 
 

Water delivered (barrels)

    62,774     25,009     37,765  

Liquids

   
 
   
 
   
 
 

Propane sold (gallons)

    1,190,106     912,625     277,481  

Other products sold (gallons)

    786,671     505,529     281,142  

Retail propane

   
 
   
 
   
 
 

Propane sold (gallons)

    162,361     144,379     17,982  

Distillates sold (gallons)

    34,965     28,853     6,112  

Refined products

   
 
   
 
   
 
 

Refined products sold (gallons)

    412,974         412,974  

Renewables

   
 
   
 
   
 
 

Renewables sold (gallons)

    150,925         150,925  

        Volumes sold by our crude oil logistics and water solutions segments were higher during the year ended March 31, 2014 than during the year ended March 31, 2013, due primarily to the expansion of our business through acquisitions.

        Volumes sold by our liquids segment were higher during the year ended March 31, 2014 than during the year ended March 31, 2013, due to several factors. Market demand for propane was higher, due in part to colder weather conditions. Market demand for butane to be used in gasoline blending operations was also higher. Volumes also increased due to the expansion of our customer base. In addition, during the year ended March 31, 2013, we upgraded two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

        Volumes sold by our retail propane segment during the year ended March 31, 2014 increased compared to the volumes sold during the year ended March 31, 2013, due primarily to colder weather conditions.

        Our refined products and renewables segments began with the December 2013 acquisition of Gavilon Energy.

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Operating Income (Loss) by Segment

        Our operating income (loss) by segment for the years ended March 31, 2014 and 2013 was as follows:

 
  Year Ended March 31,    
 
Segment
  2014   2013   Change  
 
  (in thousands)
 

Crude oil logistics

  $ 678   $ 34,236   $ (33,558 )

Water solutions

    10,317     8,576     1,741  

Liquids

    71,888     30,336     41,552  

Retail propane

    61,285     46,869     14,416  

Refined products

    4,080         4,080  

Renewables

    2,434         2,434  

Corporate and other

    (44,117 )   (32,710 )   (11,407 )
               

Operating income

  $ 106,565   $ 87,307   $ 19,258  
               
               

Crude Oil Logistics

        The following table summarizes the operating results of our crude oil logistics segment for the years ended March 31, 2014 and 2013:

 
  Year Ended March 31,    
 
 
  2014   2013   Change  
 
  (in thousands)
 

Revenues:

                   

Crude oil sales

  $ 4,559,923   $ 2,322,706   $ 2,237,217  

Crude oil transportation and other

    36,469     16,442     20,027  
               

Total revenues(1)

    4,596,392     2,339,148     2,257,244  

Expenses:

                   

Cost of sales

    4,515,244     2,267,507     2,247,737  

Operating expenses

    53,872     25,484     28,388  

General and administrative expenses

    4,487     2,745     1,742  

Depreciation and amortization expense

    22,111     9,176     12,935  
               

Total expenses

    4,595,714     2,304,912     2,290,802  
               

Segment operating income

  $ 678   $ 34,236   $ (33,558 )
               
               

(1)
Revenues include $37.8 million of intersegment sales during the year ended March 31, 2014 and $22.9 million of intersegment sales during the year ended March 31, 2013 that are eliminated in our consolidated statements of operations.

        Revenues.    Our crude oil logistics segment generated $4.6 billion of revenue from crude oil sales during the year ended March 31, 2014, selling 46.1 million barrels at an average price of $98.90 per barrel. During the year ended March 31, 2013, our crude oil logistics segment generated $2.3 billion of revenue from crude oil sales, selling 24.4 million barrels at an average price of $95.30 per barrel. The increase in volume during the year ended March 31, 2014 compared to the year ended March 31, 2013 was due in part to the fact that we did not own a crude oil logistics business for the full 12 months ended March 31, 2013, as we acquired this business in our June 19, 2012 merger with High Sierra. The increase in volume was also due to acquisitions of crude oil logistics businesses, including Gavilon

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Energy, Pecos, and Third Coast, among others. Of this increase, $1.0 billion was attributable to Gavilon Energy.

        Crude oil transportation and other revenues of our crude oil logistics segment were $36.5 million during the year ended March 31, 2014, compared to $16.4 million of crude oil transportation and other revenues during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to acquisitions of crude oil logistics businesses, including Gavilon Energy, Pecos, and Third Coast.

        Cost of Sales.    Our cost of crude oil sold was $4.5 billion during the year ended March 31, 2014, as we sold 46.1 million barrels at an average cost of $97.93 per barrel. Our cost of sales during the year ended March 31, 2014 was increased by $2.2 million of unrealized losses on derivatives. During the year ended March 31, 2013, our cost of crude oil was $2.3 billion, as we sold 24.4 million barrels at an average cost of $93.03 per barrel.

        Operating Expenses.    Our crude oil logistics segment incurred $53.9 million of operating expenses during the year ended March 31, 2014, compared to $25.5 million of operating expenses during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to the expansion of operations resulting from acquisitions, including Gavilon Energy, Pecos, and Third Coast. Of this increase, $10.1 million was attributable to Gavilon Energy.

        General and Administrative Expenses.    Our crude oil logistics segment incurred $4.5 million of general and administrative expenses during the year ended March 31, 2014, compared to $2.7 million of general and administrative expenses during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to the expansion of operations resulting from acquisitions. Of this increase, $1.0 million was attributable to our acquisition of Gavilon Energy.

        Depreciation and Amortization Expense.    Our crude oil logistics segment incurred $22.1 million of depreciation and amortization expense during the year ended March 31, 2014, compared to $9.2 million of depreciation and amortization expense during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to the expansion of operations resulting from acquisitions. Of this increase, $2.8 million was attributable to our acquisition of Gavilon Energy.

        Operating Income.    Our crude oil logistics segment generated $0.7 million of operating income during the year ended March 31, 2014, compared to $34.2 million of operating income during the year ended March 31, 2013. Acquisitions of businesses contributed to operating income during the year ended March 31, 2014, although this benefit was offset by several factors. These factors included a narrowing of price differences between markets, which reduced our opportunities to generate increased margins by transporting product from lower-price to higher-price markets, and increased competition in the South Texas region from newly-constructed pipelines. When price differences between markets are reduced, it is necessary to renegotiate price terms with producers and to not fully utilize our transportation fleet until this process has been completed and margins have improved. Operating income during the year ended March 31, 2014 was reduced by $3.0 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. We also recorded $0.5 million of employee severance expense during the year ended March 31, 2014 as a result of personnel changes subsequent to the Gavilon Energy acquisition.

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Water Solutions

        The following table summarizes the operating results of our water solutions segment for the years ended March 31, 2014 and 2013:

 
  Year Ended March 31,   Change  
 
  2014   2013   Acquisitions(1)   Other  
 
  (in thousands)
 

Revenues:

                         

Water treatment and disposal

  $ 125,788   $ 54,334   $ 64,119   $ 7,335  

Water transportation

    17,312     7,893     14,231     (4,812 )
                   

Total revenues

    143,100     62,227     78,350     2,523  

Expenses:

                         

Cost of sales

    11,738     5,611     9,325     (3,198 )

Operating expenses

    58,178     25,452     35,377     (2,651 )

General and administrative expenses

    7,762     1,665     1,239     4,858  

Depreciation and amortization expense

    55,105     20,923     26,955     7,227  
                   

Total expenses

    132,783     53,651     72,896     6,236  
                   

Segment operating income

  $ 10,317   $ 8,576   $ 5,454   $ (3,713 )
                   
                   

(1)
Represents the change in revenues and expenses attributable to acquisitions subsequent to the merger with High Sierra. The cost of sales amount shown in this column does not include derivative gains and losses, as these cannot be attributed to specific facilities.

        Revenues.    Our water solutions segment generated $125.8 million of treatment and disposal revenue during the year ended March 31, 2014, taking delivery of 62.8 million barrels of wastewater at an average revenue of $2.00 per barrel. During the year ended March 31, 2013, our water solutions segment generated $54.3 million of treatment and disposal revenue, taking delivery of 25.0 million barrels of wastewater at an average revenue of $2.17 per barrel. The increase in revenues was due primarily to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra and was due also to acquisitions during the year ended March 31, 2013, including Indigo, and acquisitions during the year ended March 31, 2014, including OWL, Big Lake and Coastal. The decrease in revenue per barrel was due primarily to the fact that the expansion of our water solutions business subsequent to our merger with High Sierra has been primarily in Texas, where the market rates for water disposal services are typically lower than in Wyoming or Colorado.

        In our June 2012 merger with High Sierra, we acquired a water transportation business in Oklahoma. In our August 2013 acquisition of OWL, we acquired a water transportation business in Texas. Our water solutions segment generated $17.3 million of transportation revenues during the year ended March 31, 2014, compared to $7.9 million of transportation revenues during the year ended March 31, 2013. This increase was due primarily to the acquisition of OWL. This increase was partially offset by a decrease in water transportation revenues generated by the water solutions business acquired in the merger with High Sierra, which resulted primarily from a slowdown in production activities by a customer. During the three months ended December 31, 2013, we wound down our water transportation operations in Oklahoma, transferring certain of the assets to our business in Texas and selling the remaining assets.

        Cost of Sales.    The cost of sales for our water solutions segment was $11.7 million during the year ended March 31, 2014. Our cost of sales during the year ended March 31, 2014 was increased by $0.6 million of unrealized losses on derivatives. Because a portion of our processing revenue is generated from the sale of recovered hydrocarbons, we enter into derivatives to protect against the risk

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of a decline in the market price of a portion of the hydrocarbons we expect to recover. During the year ended March 31, 2013, the cost of sales for our water solutions segment was $5.6 million. Our cost of sales during the year ended March 31, 2013 was increased by $1.0 million of unrealized losses on derivatives. The increase in our cost of sales was due primarily to the expansion of our operations through acquisitions of water solutions businesses.

        Operating Expenses.    Our water solutions segment incurred $58.2 million of operating expenses during the year ended March 31, 2014, compared to $25.5 million of operating expenses during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra, and was also due primarily to subsequent acquisitions of businesses. We incurred losses on disposal of property, plant and equipment of $2.0 million during the year ended March 31, 2014 as a result of property damage from lightning strikes at two of our facilities.

        General and Administrative Expenses.    Our water solutions segment incurred $7.8 million of general and administrative expenses during the year ended March 31, 2014, compared to $1.7 million of general and administrative expenses during the year ended March 31, 2013. This increase was due in part to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra, and was also due to subsequent acquisitions of businesses.

        Depreciation and Amortization Expense.    Our water solutions segment incurred $55.1 million of depreciation and amortization expense during the year ended March 31, 2014, compared to $20.9 million of depreciation and amortization expense during the year ended March 31, 2013. This increase was due in part to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra, and was also due to subsequent acquisitions of businesses. The increase is also due in part to $2.1 million of amortization expense related to trade name intangible assets. During the year ended March 31, 2014, we ceased using certain trade names and began amortizing them as finite-lived defensive assets.

        Operating Income.    Our water solutions segment generated $10.3 million of operating income during the year ended March 31, 2014, compared to operating income of $8.6 million during the year ended March 31, 2013. Exclusive of acquisitions during the year ended March 31, 2014, our operating income decreased by $3.7 million. Increases in revenues were offset by increases in operating expenses, including a $7.2 million increase in depreciation and amortization expense. The businesses acquired during the year ended March 31, 2014 generated operating income of $5.5 million, which included $27.0 million of depreciation and amortization expense, which consisted primarily of amortization expense on acquired customer relationship intangible assets.

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Liquids

        The following table summarizes the operating results of our liquids segment for the years ended March 31, 2014 and 2013:

 
  Year Ended March 31,    
 
 
  2014   2013   Change  
 
  (in thousands)
 

Revenues:

                   

Propane sales

  $ 1,632,948   $ 841,448   $ 791,500  

Other product sales

    1,231,965     858,276     373,689  

Other revenues

    31,062     33,954     (2,892 )
               

Total revenues(1)

    2,895,975     1,733,678     1,162,297  

Expenses:

                   

Cost of sales—propane

    1,559,266     801,694     757,572  

Cost of sales—other products

    1,179,944     836,747     343,197  

Cost of sales—other

    24,439     20,950     3,489  

Operating expenses

    42,977     27,605     15,372  

General and administrative expenses

    6,443     5,261     1,182  

Depreciation and amortization expense

    11,018     11,085     (67 )
               

Total expenses

    2,824,087     1,703,342     1,120,745  
               

Segment operating income

  $ 71,888   $ 30,336   $ 41,552  
               
               

(1)
Revenues include $245.6 million of intersegment sales during the year ended March 31, 2014 and $128.9 million of intersegment sales during the year ended March 31, 2013 that are eliminated in our consolidated statements of operations.

        Revenues.    Our liquids segment generated $1.6 billion of wholesale propane sales revenue during the year ended March 31, 2014, selling 1.1 billion gallons at an average price of $1.37 per gallon. During the year ended March 31, 2013, our liquids segment generated $841.4 million of wholesale propane sales revenue, selling 912.6 million gallons at an average price of $0.92 per gallon. Approximately 221.2 million gallons of the increase in volumes was due to the fact that we only owned the natural gas liquids business of High Sierra for a part of the year ended March 31, 2013. The remaining increase in volume was due to several factors, including higher market demand, due in part to colder weather conditions, and the expansion of our customer base. In addition, during the year ended March 31, 2013, we upgraded two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

        Our liquids segment generated $1.2 billion of other wholesale products sales revenue during the year ended March 31, 2014, selling 786.7 million gallons at an average price of $1.57 per gallon. During the year ended March 31, 2013, our liquids segment generated $858.3 million of other wholesale products sales revenue, selling 505.5 million gallons at an average price of $1.70 per gallon. Approximately 454.1 million gallons of the increase in volumes was due to the fact that we only owned the natural gas liquids business of High Sierra for a part of the year ended March 31, 2013. The remaining increase in volume was due to several factors, including higher market demand for butane to be used in gasoline blending operations, the expansion of our customer base, and an increased focus on the opportunity to more fully utilize our terminals to market butane.

        Cost of Sales.    Our cost of wholesale propane sales was $1.6 billion during the year ended March 31, 2014, as we sold 1.1 billion gallons at an average cost of $1.31 per gallon. Our cost of wholesale propane sales during the year ended March 31, 2014 was increased by $1.6 million of unrealized losses on derivatives. During the year ended March 31, 2013, our cost of wholesale propane

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sales was $801.7 million, as we sold 912.6 million gallons at an average cost of $0.88 per gallon. Our cost of wholesale propane sales during the year ended March 31, 2013 was reduced by $3.2 million of unrealized gains on derivatives.

        Declining wholesale propane prices during the first quarter of the prior fiscal year had an adverse effect on cost of sales during the year ended March 31, 2013. Our wholesale segment utilizes a weighted-average inventory costing method to calculate cost of sales. Propane prices decreased steadily during April and May 2012, as a result of which the replacement cost of propane was at times lower than the weighted-average cost, which had an adverse effect on margins. One of our business strategies is to purchase and store inventory during the warmer months for sale during the winter months. We seek to lock in a margin on inventory held in storage through back-to-back purchases and sales, fixed-price forward sale commitments, and financial derivatives. We also have contracts whereby we have committed to purchase ratable volumes each month at index prices. We seek to manage the price risk associated with these contracts primarily by selling the inventory immediately after it is received. When we sell product, we record the cost of the sale at the average cost of all inventory at that location, which may include inventory stored for sale in the future. During periods of rising prices, this can result in greater margins on these sales. During periods of falling prices, such as we experienced during the three months ended June 30, 2012, this can result in negative margins on these sales, which we recovered when delivering future volumes.

        Our cost of sales of other products was $1.2 billion during the year ended March 31, 2014, as we sold 786.7 million gallons at an average cost of $1.50 per gallon. Our cost of sales of other products during the year ended March 31, 2014 was reduced by $5.8 million of unrealized gains on derivatives. During the year ended March 31, 2013, our cost of sales of other products was $836.7 million, as we sold 505.5 million gallons at an average cost of $1.66 per gallon. Our cost of sales of other products during the year ended March 31, 2013 was increased by $7.5 million of unrealized losses on derivatives.

        Operating Expenses.    Our liquids segment incurred $43.0 million of operating expenses during the year ended March 31, 2014, compared to $27.6 million of operating expenses during the year ended March 31, 2013. This increase was due primarily to expanded operations. In addition, during the year ended March 31, 2014, we recorded an impairment of $5.3 million related to the property, plant and equipment of one of our terminals.

        General and Administrative Expenses.    Our liquids segment incurred $6.4 million of general and administrative expenses during the year ended March 31, 2014, compared to $5.3 million of general and administrative expenses during the year ended March 31, 2013. This increase was due primarily to expanded operations.

        Depreciation and Amortization Expense.    Our liquids segment incurred $11.0 million of depreciation and amortization expense during the year ended March 31, 2014, compared to $11.1 million of depreciation and amortization expense during the year ended March 31, 2013.

        Operating Income.    Our liquids segment generated $71.9 million of operating income during the year ended March 31, 2014, compared to $30.3 million of operating income during the year ended March 31, 2013. The increase in operating income was due primarily to the expansion of our operations and to colder weather conditions. As a result of the cold weather conditions, the demand for natural gas liquids increased considerably during the recent winter, which had a favorable impact on our sales volumes. The demand also resulted in increases to the market prices for natural gas liquids, which had a favorable impact on product margins, as we purchased inventory when prices, and therefore our average cost of inventory, were lower than when we sold the inventory. These increases were partially offset by increased operating expenses as a result of expanding our operations. During the year ended March 31, 2014, operating income was increased by $4.2 million of unrealized gains on derivatives. During the year ended March 31, 2013, operating income was reduced by $4.3 million of unrealized losses on derivatives.

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Retail Propane

        The following table summarizes the operating results of our retail propane segment for the years ended March 31, 2014 and 2013:

 
  Year Ended March 31,    
 
 
  2014   2013   Change  
 
  (in thousands)
 

Revenues:

                   

Propane sales

  $ 388,225   $ 288,410   $ 99,815  

Distillate sales

    127,672     106,192     21,480  

Other revenues

    35,918     35,856     62  
               

Total revenues

    551,815     430,458     121,357  

Expenses:

                   

Cost of sales—propane

    233,110     155,118     77,992  

Cost of sales—distillates

    109,058     90,772     18,286  

Cost of sales—other

    11,531     12,688     (1,157 )

Operating expenses

    96,936     88,651     8,285  

General and administrative expenses

    11,017     10,864     153  

Depreciation and amortization expense

    28,878     25,496     3,382  
               

Total expenses

    490,530     383,589     106,941  
               

Segment operating income

  $ 61,285   $ 46,869   $ 14,416  
               
               

        Revenues.    Our retail propane segment generated revenue of $388.2 million from propane sales during the year ended March 31, 2014, selling 162.4 million gallons at an average price of $2.39 per gallon. During the year ended March 31, 2013, our retail propane segment generated $288.4 million of revenue from propane sales, selling 144.4 million gallons at an average price of $2.00 per gallon. The increase in volumes and average sales prices during the year ended March 31, 2014 compared to the year ended March 31, 2013 was due primarily to market demand being higher as a result of colder weather conditions. Revenues also benefitted from the continued integration of previously-acquired businesses.

        Our retail propane segment generated revenue of $127.7 million from distillate sales during the year ended March 31, 2014, selling 35.0 million gallons at an average price of $3.65 per gallon. During the year ended March 31, 2013, our retail propane segment generated $106.2 million of revenue from distillate sales, selling 28.9 million gallons at an average price of $3.68 per gallon. The increase in volumes was due primarily to colder weather conditions and to the acquisitions of smaller retailers.

        Cost of Sales.    Our cost of retail propane sales was $233.1 million during the year ended March 31, 2014, as we sold 162.4 million gallons at an average cost of $1.44 per gallon. During the year ended March 31, 2013, our cost of retail propane sales was $155.1 million, as we sold 144.4 million gallons at an average cost of $1.07 per gallon.

        Our cost of distillate sales was $109.1 million during the year ended March 31, 2014, as we sold 35.0 million gallons at an average cost of $3.12 per gallon. During the year ended March 31, 2013, our cost of distillate sales was $90.8 million, as we sold 28.9 million gallons at an average cost of $3.15 per gallon.

        Operating Expenses.    Our retail propane segment incurred $96.9 million of operating expenses during the year ended March 31, 2014, compared to $88.7 million of operating expenses during the year ended March 31, 2013. This increase was due in part to the inclusion of Downeast in our results of operations for the full 12 months ended March 31, 2014, as compared to only 11 of the months in the 12-month period ended March 31, 2013.

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        General and Administrative Expenses.    Our retail propane segment incurred $11.0 million of general and administrative expenses during the year ended March 31, 2014, compared to $10.9 million of general and administrative expenses during the year ended March 31, 2013. This increase was due primarily to acquisitions of smaller retailers.

        Depreciation and Amortization Expense.    Our retail propane segment incurred $28.9 million of depreciation and amortization expense during the year ended March 31, 2014, compared to $25.5 million of depreciation and amortization expense during the year ended March 31, 2013. This increase was due primarily to capital expenditures and acquisitions.

        Operating Income.    Our retail propane segment generated $61.3 million of operating income during the year ended March 31, 2014, compared to $46.9 million of operating income during the year ended March 31, 2013. The increase in operating income was due primarily to increased market demand due to colder weather conditions, partially offset by increased operating expenses.

Refined Products

        The following table summarizes the operating results of our refined products segment for the year ended March 31, 2014 (in thousands). Our refined products segment began with our December 2013 acquisition of Gavilon Energy.

Revenues

  $ 1,180,895  

Expenses:

   
 
 

Cost of sales

    1,172,754  

Operating expenses

    3,887  

General and administrative expenses

    65  

Depreciation and amortization expense

    109  
       

Total expenses

    1,176,815  
       

Segment operating income

  $ 4,080  
       
       

        Revenues.    Our refined products segment generated $1.2 billion of revenue during the year ended March 31, 2014, selling 413.0 million gallons at an average price of $2.86 per gallon.

        Cost of Sales.    Our cost of sales was $1.2 billion during the year ended March 31, 2014, as we sold 413.0 million gallons at an average cost of $2.84 per gallon.

        Operating Expenses.    Our refined products segment incurred $3.9 million of operating expenses during the year ended March 31, 2014.

        General and Administrative Expenses.    Our refined products segment incurred $0.1 million of general and administrative expenses during the year ended March 31, 2014.

        Depreciation and Amortization Expense.    Our refined products segment incurred $0.1 million of depreciation and amortization expense during the year ended March 31, 2014.

        Operating Income.    Our refined products segment generated $4.1 million of operating income during the year ended March 31, 2014.

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Renewables

        The following table summarizes the operating results of our renewables segment for the year ended March 31, 2014 (in thousands). Our renewables segment began with our December 2013 acquisition of Gavilon Energy.

Revenues

  $ 176,781  

Expenses:

   
 
 

Cost of sales

    171,422  

Operating expenses

    2,318  

General and administrative expenses

    91  

Depreciation and amortization expense

    516  
       

Total expenses

    174,347  
       

Segment operating income

  $ 2,434  
       
       

        Revenues.    Our renewables segment generated $176.8 million of revenue during the year ended March 31, 2014, selling 150.9 million gallons at an average price of $1.17 per gallon.

        Cost of Sales.    Our cost of sales was $171.4 million during the year ended March 31, 2014, as we sold 150.9 million gallons at an average cost of $1.14 pergallon.

        Operating Expenses.    Our renewables segment incurred $2.3 million of operating expenses during the year ended March 31, 2014.

        General and Administrative Expenses.    Our renewables segment incurred $0.1 million of general and administrative expenses during the year ended March 31, 2014.

        Depreciation and Amortization Expense.    Our renewables segment incurred $0.5 million of depreciation and amortization expense during the year ended March 31, 2014.

        Operating Income.    Our renewables segment generated $2.4 million of operating income during the year ended March 31, 2014.

Corporate and Other

        The operating loss within "corporate and other" includes the following components:

 
  Year Ended March 31,    
 
 
  2014   2013   Change  
 
  (in thousands)
 

Compressor leasing business

  $ 2,336   $ (1 ) $ 2,337  

Natural gas business

    1,363         1,363  

Equity-based compensation expense

    (17,804 )   (10,138 )   (7,666 )

Acquisition expenses

    (6,908 )   (5,602 )   (1,306 )

Other corporate expenses

    (23,104 )   (16,969 )   (6,135 )
               

  $ (44,117 ) $ (32,710 ) $ (11,407 )
               
               

        Operating income of our compressor leasing business for the year ended March 31, 2014 includes a $4.4 million gain from the sale of the business in February 2014.

        We acquired the natural gas business in our December 2013 acquisition of Gavilon Energy. We subsequently wound down the natural gas business and, as of March 31, 2014, this business has no revenue-generating activity.

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        The increase in equity-based compensation is due in part to the timing of award grants and is also due in part to an increase in the market value of our common units. The first restricted units were granted during fiscal 2013, and therefore were not in existence for the full fiscal year. The life-to-date expense for unvested units is adjusted based on the market value of the common units on the reporting date, and the value of the common units was higher at March 31, 2014 than at March 31, 2013.

        The increase in other corporate expenses is due primarily to increases in compensation expense, due to the addition of new corporate employees to provide general and administrative services in support of the growth of our business.

        Operating income during the year ended March 31, 2014 was reduced by $2.0 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. We also recorded $2.2 million of employee severance expense during the year ended March 31, 2014 as a result of personnel changes subsequent to the Gavilon Energy acquisition, $1.3 million of which is reported under "natural gas business" in the table above and the remainder of which is reported under "other corporate expenses" in the table above.


Year Ended March 31, 2013
Compared to Year Ended March 31, 2012

Volumes Sold or Delivered

        The following table summarizes the volume of product sold and water delivered for the years ended March 31, 2013 and 2012. Volumes shown in the table below for our liquids segment include sales to our retail propane segment.

 
  Year Ended
March 31,
  Change Resulting From  
 
  Retail
Combinations(1)
  SemStream
Combination
  High Sierra
Combinations(2)
   
 
Segment
  2013   2012   Other  
 
  (in thousands)
   
   
   
   
 

Crude oil logistics

                                     

Crude oil sold (barrels)

    24,373                 24,373      

Water solutions

   
 
   
 
   
 
   
 
   
 
   
 
 

Water delivered (barrels)

    25,009                 25,009      

Liquids

   
 
   
 
   
 
   
 
   
 
   
 
 

Propane sold (gallons)

    912,625     659,921           (3)   140,632     112,072  

Other products sold (gallons)

    505,529     134,999           (3)   320,283     50,247  

Retail propane

   
 
   
 
   
 
   
 
   
 
   
 
 

Propane sold (gallons)

    144,379     78,236     54,949             11,194  

Distillates sold (gallons)

    28,853     1,650     27,027             176  

(1)
This data includes the operations of Osterman (acquired in October 2011) from April 1, 2012 through September 30, 2012, Pacer (acquired in January 2012) from April 1, 2012 through December 31, 2012, North American (acquired in February 2012) from April 1, 2012 through January 31, 2013, Downeast (acquired in May 2012), and certain other smaller retail propane business acquired during fiscal 2013.

(2)
This data includes the operations of High Sierra (acquired in June 2012), Pecos (acquired in November 2012), and other subsequent acquisitions of smaller crude oil and water solutions businesses.

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(3)
Although the SemStream combination enabled us to significantly expand our wholesale operations, it is not possible to determine which of the volumes sold subsequent to the combination were specifically attributable to the SemStream combination and which were attributable to our historical wholesale business.

        As shown in the table above, the increases in volumes were driven primarily by acquisitions of businesses during fiscal 2012 and fiscal 2013. The remaining increase in volume of our retail propane business was due primarily to colder weather during the 2013-2014 winter season, which increased the demand for propane.

Operating Income by Segment

        Our operating income by segment is as follows:

 
  Year Ended March 31,    
 
Segment
  2013   2012   Change  
 
  (in thousands)
 

Crude oil logistics

  $ 34,236   $   $ 34,236  

Water solutions

    8,576         8,576  

Liquids

    30,336     9,735     20,601  

Retail propane

    46,869     9,616     37,253  

Corporate and other

    (32,710 )   (4,321 )   (28,389 )
               

Operating income

  $ 87,307   $ 15,030   $ 72,277  
               
               

        The operating loss within "corporate and other" increased $28.4 million during the year ended March 31, 2013 as compared to $4.3 million during the year ended March 31, 2012. This increase is due in part to $8.4 million of incremental expenses associated with the corporate activities of High Sierra. In addition, corporate general and administrative expense for the year ended March 31, 2013 includes $10.1 million of compensation expense related to certain restricted units granted pursuant to employee and director compensation programs. Corporate general and administrative expense for the year ended March 31, 2013 also includes costs related to acquisitions, including $3.7 million of expense related to the acquisition of High Sierra. The operations of our compressor leasing business are also included within "corporate and other."

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Crude Oil Logistics

        The following table summarizes the operating results of our crude oil logistics segment for the year ended March 31, 2013 (amounts in thousands). The operations of our crude oil logistics segment began with our June 19, 2012 combination with High Sierra.

Revenues:

       

Crude oil sales

  $ 2,322,706  

Crude oil transportation and other

    16,442  
       

Total revenues(1)

    2,339,148  

Expenses:

       

Cost of sales

    2,267,507  

Operating expenses

    25,484  

General and administrative expenses

    2,745  

Depreciation and amortization expense

    9,176  
       

Total expenses

    2,304,912  
       

Segment operating income

  $ 34,236  
       
       

(1)
Revenues include $22.9 million of intersegment sales that are eliminated in our consolidated statement of operations.

        Revenues.    We generated revenue of $2.3 billion from crude oil sales during the year ended March 31, 2013, selling 24.4 million barrels at an average price of $95.30 per barrel. We also generated $16.4 million of revenue from the transportation of crude oil owned by other parties.

        Cost of Sales.    Our cost of crude oil sold was $2.3 billion during the year ended March 31, 2013. We sold 24.4 million barrels at an average cost of $93.03 per barrel. Our cost of sales during the year ended March 31, 2013 was increased by $9.8 million of realized losses on derivatives.

        Other Operating Expenses.    Our crude oil operations incurred $28.2 million of operating and general and administrative expenses during the year ended March 31, 2013. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $9.2 million during the year ended March 31, 2013.

Water Solutions

        The following table summarizes the operating results of our water solutions segment for the year ended March 31, 2013 (amounts in thousands). The operations of our water solutions segment began with our June 19, 2012 combination with High Sierra.

Revenues:

       

Water treatment and disposal

  $ 54,334  

Water transportation

    7,893  
       

Total revenues

    62,227  

Expenses:

       

Cost of sales

    5,611  

Operating expenses

    25,452  

General and administrative expenses

    1,665  

Depreciation and amortization expense

    20,923  
       

Total expenses

    53,651  
       

Segment operating income

  $ 8,576  
       
       

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        Revenues.    Our water solutions segment generated $54.3 million of treatment and disposal revenue during the year ended March 31, 2013, taking delivery of 25.0 million barrels of wastewater at an average revenue of $2.17 per barrel. Our water transportation business generated $7.9 million of revenues.

        Cost of Sales.    The cost of sales for our water solutions segment was $5.6 million for the year ended March 31, 2013, an average cost of $0.22 per barrel delivered. Cost of sales was increased by unrealized losses of $1.0 million and realized losses of $0.8 million on derivatives. A portion of our processing revenue is generated from the sale of recovered hydrocarbons; we enter into these derivatives to protect against the risk of a decline in the market price of a portion of the hydrocarbons we expect to recover.

        Other Operating Expenses.    Our water solutions segment incurred $27.1 million of operating and general and administrative expenses during the year ended March 31, 2013. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $20.9 million during the year ended March 31, 2013.

Liquids

        The following table compares the operating results of our liquids segment for the years ended March 31, 2013 and 2012:

 
   
   
  Change Resulting From  
 
  Year Ended March 31,    
   
 
 
  High Sierra
Combination
   
 
 
  2013   2012   Other  
 
  (in thousands)
 

Revenues:

                         

Propane sales

  $ 841,448   $ 923,022   $ 115,606   $ (197,180 )

Other product sales

    858,276     251,627     563,211     43,438  

Other revenues

    33,954     2,462     19,053     12,439  
                   

Total revenues(1)

    1,733,678     1,177,111     697,870     (141,303 )

Expenses:

   
 
   
 
   
 
   
 
 

Cost of sales—propane

    801,694     904,082     109,851     (212,239 )

Cost of sales—other products

    836,747     246,995     546,588     43,164  

Costs of sales—other

    20,950     1,776     8,637     10,537  

Operating expenses

    27,605     8,124     15,097     4,384  

General and administrative expenses

    5,261     2,738     1,693     830  

Depreciation and amortization expense          

    11,085     3,661     3,101     4,323  
                   

Total expenses

    1,703,342     1,167,376     684,967     (149,001 )
                   

Segment operating income

  $ 30,336   $ 9,735   $ 12,903   $ 7,698  
                   
                   

(1)
Revenues include $128.9 million of intersegment sales during the year ended March 31, 2013 and $66.0 million of intersegment sales during the year ended March 31, 2012 that are eliminated in our consolidated statements of operations.

        Revenues.    Exclusive of the operations acquired in our June 2012 merger with High Sierra, revenues from wholesale propane sales decreased $197.2 million during the year ended March 31, 2013, as compared to $923.0 million during the year ended March 31, 2012. This resulted from a decrease in the average selling price of $0.46 per gallon, as compared to an average selling price per gallon of $1.40 in the prior year. This decrease in revenue was partially offset by an increase in volume sold of 112.1 million gallons, as compared to 659.9 million gallons sold in the prior year.

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        During the year ended March 31, 2013, the operations of High Sierra contributed revenues of $115.6 million from propane sales. These operations sold 140.6 million gallons of propane at an average price of $0.82 per gallon.

        Exclusive of the operations acquired in our June 2012 merger with High Sierra, revenues from wholesale sales of other products increased $43.4 million during the year ended March 31, 2013, as compared to $251.6 million during the year ended March 31, 2012. This resulted from an increase in volume sold of 50.2 million gallons as compared to 135.0 million gallons in the prior year, partially offset by a decrease in the average selling price of $0.27 per gallon, as compared to $1.86 per gallon in the prior year.

        During the year ended March 31, 2013, the operations of High Sierra contributed revenues of $563.2 million from sales of other products (primarily butane). These operations sold 320.3 million gallons of other products at an average price of $1.76 per gallon.

        Exclusive of the operations acquired in our June 2012 merger with High Sierra, the increase in volume sold is due primarily to the November 2011 SemStream acquisition, which expanded the markets we are able to serve. We believe the decline in average selling prices is due primarily to a greater than normal supply in the marketplace, due in part to low demand as a result of mild weather.

        Transportation and other revenues for the year ended March 31, 2013 relate primarily to fees charged for transporting customer-owned product by railcar.

        Cost of Sales.    Exclusive of the operations acquired in our June 2012 merger with High Sierra, costs of wholesale propane sales decreased $212.2 million during the year ended March 31, 2013, as compared to $904.1 million during the year ended March 31, 2012. This resulted from a decrease in the average cost of $0.47 per gallon, as compared to an average cost per gallon of $1.37 in the prior year. This decrease in cost was partially offset by an increase in volume sold of 112.1 million gallons, as compared to 659.9 million gallons sold in the prior year. Cost of propane sales were reduced by $14.8 million during the year ended March 31, 2013 due to $11.6 million of realized gains and $3.2 million of unrealized gains on derivatives. These derivatives consisted primarily of propane swaps that we entered into as economic hedges against the potential decline in the market value of our propane inventories. Excluding gains on derivatives, our average cost of propane sold during the year ended March 31, 2013 was $0.92 cents per gallon.

        During the year ended March 31, 2013, the cost of propane sales of the High Sierra operations were $109.9 million. These operations sold 140.6 million gallons of propane at an average price of $0.78 per gallon.

        Exclusive of the operations acquired in our June 2012 merger with High Sierra, cost of wholesale sales of other products increased $43.2 million during the year ended March 31, 2013, as compared to $247.0 million during the year ended March 31, 2012. This resulted from an increase in volume sold of 50.2 million gallons as compared to 135.0 million gallons in the prior year, partially offset by a decrease in the average cost of $0.26 per gallon, as compared to $1.83 per gallon in the prior year. Cost of other products sales during the year ended March 31, 2013 was reduced by $0.2 million due to realized gains on derivatives.

        During the year ended March 31, 2013, the cost of other products sales of the High Sierra operations was $546.6 million. These operations sold 320.3 million gallons of other products (primarily butane) at an average price of $1.71 per gallon. Costs of sales of other products during the year ended March 31, 2013 were increased by $7.5 million of unrealized losses and $0.3 million of realized losses on derivatives.

        Other cost of sales for the year ended March 31, 2013 relate primarily to the cost of leasing railcars used in the transportation of customer-owned product.

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        Operating Expenses.    Exclusive of the operations acquired in our June 2012 merger with High Sierra, operating expenses of our liquids segment increased $4.4 million during the year ended March 31, 2013 as compared to operating expenses of $8.1 million during the year ended March 31, 2012. The increase in operating expenses is due primarily to increased compensation and terminal operating expenses resulting from our SemStream combination. During the year ended March 31, 2013, our liquids segment incurred $15.1 million of operating expenses related to the operations of High Sierra.

        General and Administrative Expenses.    Exclusive of the operations acquired in our June 2012 merger with High Sierra, general and administrative expenses of our liquids segment increased $0.8 million during the year ended March 31, 2013 as compared to general and administrative expenses of $2.7 million during the year ended March 31, 2012. This increase is due primarily to increased compensation and related expenses resulting from our SemStream combination. During the year ended March 31, 2013, our liquids segment incurred $1.7 million of general and administrative expenses related to the operations of High Sierra.

        Depreciation and Amortization Expense.    Exclusive of the operations acquired in our June 2012 merger with High Sierra, depreciation and amortization expense of our liquids segment increased $4.3 million during the year ended March 31, 2013, as compared to depreciation and amortization expense of $3.7 million during the year ended March 31, 2012. This increase is due primarily to depreciation and amortization expense related to assets acquired in the SemStream combination, including depreciation of terminal assets and amortization of customer relationship intangible assets. During the year ended March 31, 2013, our liquids segment recorded $3.1 million of depreciation and amortization expense related to assets acquired in our merger with High Sierra.

        Operating Income.    Our liquids segment had operating income of $30.3 million during the year ended March 31, 2013 as compared to operating income of $9.7 million during the year ended March 31, 2012. The increased operating income is due in part to $12.9 million of operating income contributed by the operations acquired in the merger with High Sierra. Exclusive of these operations, operating income improved by $7.7 million, which was due to increased product margins, partially offset by increased expenses.

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Retail Propane

        The following table compares the operating results of our retail propane segment for the years ended March 31, 2013 and 2012:

 
   
   
  Change Resulting From  
 
  Year Ended March 31,  
 
  Retail
Combinations(1)
   
 
 
  2013   2012   Other  
 
  (in thousands)
 

Revenues:

                         

Propane sales

  $ 288,410   $ 175,417   $ 117,686   $ (4,693 )

Distillate sales

    106,192     6,547     99,410     235  

Other sales

    35,856     17,370     20,752     (2,266 )
                   

Total revenues

    430,458     199,334     237,848     (6,724 )

Expenses:

                         

Cost of sales—propane

    155,118     117,722     63,080     (25,684 )

Cost of sales—distillates

    90,772     5,728     84,933     111  

Cost of sales—other

    12,688     6,692     6,516     (520 )

Operating expenses

    88,651     39,176     47,454     2,021  

General and administrative expenses

    10,864     8,950     5,409     (3,495 )

Depreciation and amortization expense

    25,496     11,450     13,059     987  
                   

Total expenses

    383,589     189,718     220,451     (26,580 )
                   

Segment operating income

  $ 46,869   $ 9,616   $ 17,397   $ 19,856  
                   
                   

(1)
This data includes the operations of Osterman (acquired in October 2011) from April 1, 2012 through September 30, 2012, Pacer (acquired in January 2012) from April 1, 2012 through December 31, 2012, North American (acquired in February 2012) from April 1, 2012 through January 31, 2013, Downeast (acquired in May 2012), and certain other smaller retail propane business acquired during fiscal 2013.

        Revenues.    Propane sales for the year ended March 31, 2013 increased $113.0 million as compared to propane sales of $175.4 million during the year ended March 31, 2012. The principal reason for the increase in propane sales was the acquisitions of Osterman, Pacer, North American, and Downeast. Excluding the impact of these acquisitions, propane sales were lower during the year ended March 31, 2013 than during the year ended March 31, 2012, due primarily to a decline in the average price per gallon sold of $0.33 during the year ended March 31, 2013, as compared to an average price per gallon sold of $2.24 during the year ended March 31, 2012. Excluding the effect of these acquisitions, volumes sold during the year ended March 31, 2013 were higher than volumes sold during the year ended March 31, 2012, due primarily to the fact that the fiscal 2013 winter was colder than that of fiscal 2012. The winter of fiscal 2012 was one of the warmest on record, and these warm weather conditions resulted in a decrease in the demand for propane.

        Our acquired Osterman, Pacer, North American, and Downeast operations generated propane sales of $117.7 million during the year ended March 31, 2013, consisting of 54.9 million gallons sold at an average price of $2.14 per gallon. The average selling price per gallon for the acquired operations was higher than the average selling price for our historical operations, due in part to the fact that the markets served by the acquired operations are, in general, further away from the primary areas of propane supply than are the markets served by our historical operations.

        We generated $106.2 million of revenue from the sales of distillates during the year ended March 31, 2013, consisting of 28.9 million gallons sold at an average selling price of $3.68 per gallon.

        Cost of Sales.    Propane cost of sales for the year ended March 31, 2013 increased $37.4 million as compared to propane cost of sales of $117.7 million during the year ended March 31, 2012. This

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increase in propane cost of sales is due primarily to the acquisitions of Osterman, Pacer, North American, and Downeast. Excluding the impact of these acquisitions, propane cost of sales was lower during the year ended March 31, 2013 than during the year ended March 31, 2012, due primarily to a decline in the average cost per gallon sold of $0.47 during the year ended March 31, 2013, as compared to an average price per gallon sold of $1.50 during the year ended March 31, 2012. Excluding the effect of these acquisitions, volumes sold during the year ended March 31, 2013 were higher than volumes sold during the year ended March 31, 2012, due primarily to the fact that the fiscal 2013 winter was colder than that of fiscal 2012.

        Our acquired Osterman, Pacer, North American, and Downeast operations had propane cost of sales of $63.1 million during the year ended March 31, 2013, consisting of 54.9 million gallons sold at an average cost of $1.15 per gallon. The average cost per gallon for the acquired operations was higher than the average cost for our historical operations, due in part to the fact that the markets served by the acquired operations are, in general, further away from the primary areas of propane supply than are the markets served by our historical operations.

        We had $90.8 million of cost of sales for distillates during the year ended March 31, 2013, consisting of 28.9 million gallons sold at an average cost of $3.15 per gallon.

        Operating Expenses.    Operating expenses of our retail propane segment increased $49.5 million during the year ended March 31, 2013 as compared to operating expenses of $39.2 million during the year ended March 31, 2012. This increase is due primarily to the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which incurred $47.5 million of operating expense during the year ended March 31, 2013.

        General and Administrative Expenses.    General and administrative expenses of our retail propane segment increased $1.9 million during the year ended March 31, 2013 as compared to general and administrative expenses of $9.0 million during the year ended March 31, 2012. The principal factor causing the increase is the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which incurred $5.4 million of general and administrative expense during the year ended March 31, 2013. General and administrative expense included $4.3 million of acquisition expenses during the year ended March 31, 2012.

        Depreciation and Amortization.    Depreciation and amortization expense of our retail propane segment increased $14.0 million during the year ended March 31, 2013 as compared to depreciation and amortization expense of $11.5 million during the year ended March 31, 2012. The increase is due primarily to the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which incurred $13.1 million of depreciation and amortization expense during the year ended March 31, 2013.

        Operating Income.    Our retail propane segment had operating income of $46.9 million during the year ended March 31, 2013 compared to operating income of $9.6 million during the year ended March 31, 2012. The increased operating income is due in part to the acquired operations of Osterman, Pacer, North American, and Downeast. Excluding these acquired operations, our retail propane segment's operating income was higher during the year ended March 31, 2013 than during the year ended March 31, 2012, due primarily to improved margins on propane sales, and to increased sales volumes. During the year ended March 31, 2012, the winter was one of the warmest on record. As a result, demand for propane was low, which resulted in reduced sales volumes during fiscal 2012.

Seasonality

        Seasonality impacts our liquids and retail propane segments. A large portion of our retail propane operation is in the residential market where propane is used primarily for heating. During the year ended March 31, 2014, 74% of our retail propane volume was sold during the peak heating season

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from October through March. Consequently, for these two segments, sales, operating profits and operating cash flows are generated mostly in the third and fourth quarters of each fiscal year. See "—Liquidity, Sources of Capital and Capital Resource Activities—Cash Flows."

Liquidity, Sources of Capital and Capital Resource Activities

        Our principal sources of liquidity and capital are the cash flows from our operations and borrowings under our Revolving Credit Facility. Our cash flows from operations are discussed below.

        Our borrowing needs vary significantly during the year due to the seasonal nature of our business. Our greatest working capital borrowing needs generally occur during the period of June through December, when we are building our natural gas liquids inventories in anticipation of the heating season. Our working capital borrowing needs generally decline during the period of January through March, when the cash flows from our retail propane and liquids segments are the greatest.

        Our partnership agreement requires that, within 45 days after the end of each quarter we distribute all of our available cash (as defined in our partnership agreement) to unitholders as of the record date. Available cash for any quarter generally consists of all cash on hand at the end of that quarter, less the amount of cash reserves established by our general partner, to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any of our debt instruments or other agreements, and (iii) provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters. TLP's partnership agreement also requires that, within 45 days after the end of each quarter it distribute all of its available cash (as defined in its partnership agreement) to its unitholders as of the record date. Available cash is defined similarly in TLP's partnership agreement and our partnership agreement.

        We believe that our anticipated cash flows from operations and the borrowing capacity under our Revolving Credit Facility are sufficient to meet our liquidity needs for the next 12 months. If our plans or assumptions change or are inaccurate, or if we make acquisitions, we may need to raise additional capital. Our ability to raise additional capital, if necessary, depends on various factors and conditions, including market conditions. We cannot give any assurances that we can raise additional capital to meet these needs. Commitments or expenditures, if any, we may make toward any acquisition projects are at our discretion.

        We continue to pursue a strategy of growth through acquisitions. We expect to consider financing future acquisitions through a variety of sources, including the use of available capacity on our Revolving Credit Facility, the issuance of equity to sellers of the businesses we acquire, private placements of common units or debt securities, and public offerings of common units or debt securities. Our ability to raise additional capital through the issuance of debt or equity securities will have a significant impact on our ability to continue to pursue our growth strategy.

Credit Agreement

        On June 19, 2012, we entered into a credit agreement (as amended, the "Credit Agreement") with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the "Working Capital Facility") and a revolving credit facility to fund acquisitions and expansion projects (the "Expansion Capital Facility," and together with the Working Capital Facility, the "Revolving Credit Facility").

        The Working Capital Facility had a total capacity of $1.335 billion for cash borrowings and letters of credit at September 30, 2014. At that date, we had outstanding borrowings of $942.5 million and outstanding letters of credit of $209.2 million on the Working Capital Facility. The Expansion Capital Facility had a total capacity of $858.0 million for cash borrowings at September 30, 2014. At that date, we had outstanding borrowings of $137.0 million on the Expansion Capital Facility. The capacity

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available under the Working Capital Facility may be limited by a "borrowing base," as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time.

        The commitments under the Credit Agreement expire on November 5, 2018. We have the right to prepay outstanding borrowings under the Credit Agreement without incurring any penalties, and prepayments of principal may be required if we enter into certain transactions to sell assets or obtain new borrowings.

        All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 0.50% to 1.50% per annum or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At September 30, 2014, all borrowings under the Credit Agreement were LIBOR borrowings with an interest rate at September 30, 2014 of 1.91%, calculated as the LIBOR rate of 0.16% plus a margin of 1.75%. At September 30, 2014, the interest rate in effect on letters of credit was 2.00%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. At September 30, 2014, our outstanding borrowings and interest rates under our Revolving Credit Facility were as follows (dollars in thousands):

 
  Amount   Rate  

Expansion Capital Facility—

             

LIBOR borrowings

  $ 137,000     1.91 %

Working Capital Facility—

             

LIBOR borrowings

    942,500     1.91 %

        The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our leverage ratio, as defined in the Credit Agreement, cannot exceed 4.25 to 1 at any quarter end. At September 30, 2014, our leverage ratio was approximately 3.4 to 1. The Credit Agreement also specifies that our interest coverage ratio, as defined in the Credit Agreement, cannot be less than 2.75 to 1 at any quarter end. At September 30, 2014, our interest coverage ratio was approximately 4.8 to 1.

        The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.

        At September 30, 2014, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

        On July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the "2019 Notes") in a private placement exempt from registration under the Securities Act of 1933, as amended (the "Securities Act"), pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $393.5 million, after the initial purchasers' discount of $6.0 million and estimated offering costs of $0.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

        The 2019 Notes mature on July 15, 2019. Interest is payable on January 15 and July 15 of each year. We have the right to redeem the 2019 Notes prior to the maturity date, although we would be required to pay a premium price for early redemption.

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        The Partnership and NGL Energy Finance Corp. are co-issuers of the 2019 Notes, and the obligations under the 2019 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The purchase agreement and the indenture governing the 2019 Notes contain various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

        At September 30, 2014, we were in compliance with the covenants under the purchase agreement and indenture governing the 2019 Notes.

        We also entered into a registration rights agreement whereby we have committed to exchange the 2019 Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the 2019 Notes on or before July 9, 2015. If we are unable to fulfill this obligation, we would be required to pay liquidated damages to the holders of the 2019 Notes.

2021 Notes

        On October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the "2021 Notes") in a private placement exempt from registration under the Securities Act pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $438.4 million, after the initial purchasers' discount of $10.1 million and offering costs of $1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

        The 2021 Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the 2021 Notes prior to the maturity date, although we would be required to pay a premium for early redemption.

        The Partnership and NGL Energy Finance Corp. are co-issuers of the 2021 Notes, and the obligations under the 2021 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The purchase agreement and the indenture governing the 2021 Notes contain various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

        At September 30, 2014, we were in compliance with the covenants under the purchase agreement and indenture governing the 2021 Notes.

        We also entered into a registration rights agreement whereby we have committed to exchange the 2021 Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the 2021 Notes on or before October 16, 2014. Our inability to register the notes on time may result in liquidated damages of approximately $0.1 million per month.

2022 Notes

        On June 19, 2012, we entered into a Note Purchase Agreement (as amended, the "Note Purchase Agreement") whereby we issued $250.0 million of Senior Notes in a private placement (the "2022 Notes"). The 2022 Notes bear interest at a fixed rate of 6.65%. Interest is payable quarterly. The 2022

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Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to prepay outstanding principal, although we would incur a prepayment penalty. The 2022 Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

        The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create or permit certain liens, (iv) create or permit restrictions on the ability of certain of our subsidiaries to pay dividends or make other distributions to us, (v) enter into transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate or merge or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains substantially the same leverage ratio and interest coverage ratio requirements as our Credit Agreement, which is described above.

        The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary grace and cure periods): (i) nonpayment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the 2022 Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the Note Purchase Agreement, the 2022 Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregate principal amount of the then outstanding 2022 Notes of any series may declare all of the 2022 Notes of such series to be due and payable immediately.

        At September 30, 2014, we were in compliance with the covenants under the Note Purchase Agreement.

TLP Credit Facility

        On March 9, 2011, TLP entered into an amended and restated senior secured credit facility ("TLP Credit Facility"), which has been subsequently amended from time to time. The TLP Credit Facility provides for a maximum borrowing line of credit equal to the lesser of (i) $350 million and (ii) 4.75 times Consolidated EBITDA (as defined in the TLP Credit Facility: $352.9 million at September 30, 2014). TLP may elect to have loans under the TLP Credit Facility that bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLP also pays a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.50% per annum, depending on the total leverage ratio then in effect. TLP's obligations under the TLP Credit Facility are secured by a first priority security interest in favor of the lenders in the majority of TLP assets.

        The terms of the TLP Credit Facility include covenants that restrict TLP's ability to make cash distributions, acquisitions and investments, including investments in joint ventures. TLP may make distributions of cash to the extent of its "available cash" as defined in the TLP partnership agreement. TLP may make acquisitions and investments that meet the definition of "permitted acquisitions"; "other investments" which may not exceed 5% of "consolidated net tangible assets"; and "permitted JV investments". Permitted JV investments include up to $225 million of investments in BOSTCO, the "Specified BOSTCO Investment". In addition to the Specified BOSTCO Investment, under the terms of the TLP Credit Facility, TLP may make an additional $75 million of other permitted JV investments

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(including additional investments in BOSTCO). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 9, 2016.

        The TLP Credit Facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the TLP Credit Facility are (i) a total leverage ratio test (not to exceed 4.75 times), (ii) a senior secured leverage ratio test (not to exceed 3.75 times) in the event TLP issues senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times).

        If TLP were to fail any financial performance covenant, or any other covenant contained in the TLP Credit Facility, TLP would seek a waiver from its lenders under such facility. If TLP was unable to obtain a waiver from its lenders and the default remained uncured after any applicable grace period, TLP would be in breach of the TLP Credit Facility, and the lenders would be entitled to declare all outstanding borrowings immediately due and payable. TLP was in compliance with all of the financial covenants under the TLP Credit Facility as of September 30, 2014.

        At September 30, 2014, TLP had $252.0 million of outstanding borrowings under the TLP Credit Facility and no outstanding letters of credit.

        The following table summarizes our basis in the assets and liabilities of TLP at September 30, 2014, inclusive of the impact of our acquisition accounting for the business combination with TransMontaigne (in thousands):

Cash and cash equivalents

  $ 726  

Accounts receivable—trade, net

    12,252  

Accounts receivable—affiliates

    1,105  

Inventories

    1,613  

Prepaid expenses and other current assets

    1,363  

Property, plant and equipment, net

    504,272  

Goodwill

    29,118  

Intangible assets, net

    38,571  

Investments in unconsolidated entities

    268,410  

Other noncurrent assets

    1,910  

Accounts payable—trade

    (4,009 )

Accounts payable—affiliates

    (146 )

Accrued expenses and other payables

    (11,625 )

Advance payments received from customers

    (141 )

Long-term debt

    (252,000 )

Other noncurrent liabilities

    (4,247 )
       

Net assets

  $ 587,172  
       
       

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Revolving Credit Balances

        The following table summarizes Revolving Credit Facility borrowings:

 
  Average
Daily
Balance
  Lowest
Balance
  Highest
Balance
 
 
  (in thousands)
 

Six Months Ended September 30, 2014:

                   

Expansion borrowings

  $ 346,855   $ 114,000   $ 578,500  

Working capital borrowings

    640,369     339,500     1,024,500  

TLP credit facility

    246,750     228,000     258,500  

Six Months Ended September 30, 2013:

   
 
   
 
   
 
 

Expansion borrowings

  $ 440,423   $ 255,000   $ 546,000  

Working capital borrowings

    80,779         229,500  

Business Combinations

        Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, as described under "Business—Acquisitions Subsequent to Initial Public Offering."

Cash Flows

        The following summarizes the sources (uses) of our cash flows:

 
  Six Months Ended
September 30,
 
Cash Flows Provided by (Used in):
  2014   2013  
 
  (in thousands)
 

Operating activities, before changes in operating assets and liabilities

  $ 19,091   $ 60,976  

Changes in operating assets and liabilities

    (80,726 )   (109,720 )
           

Operating activities

  $ (61,635 ) $ (48,744 )

Investing activities

    (750,288 )   (476,854 )

Financing activities

    813,306     519,565  

 

 
  Year Ended March 31,  
Cash Flows Provided by (Used in):
  2014   2013   2012  
 
  (in thousands)
 

Operating activities, before changes in operating assets and liabilities

  $ 243,303   $ 146,395   $ 20,459  

Changes in operating assets and liabilities

    (158,067 )   (13,761 )   69,870  
               

Operating activities

  $ 85,236   $ 132,634   $ 90,329  

Investing activities

    (1,455,373 )   (546,621 )   (296,897 )

Financing activities

    1,369,016     417,716     198,063  

        Operating Activities.    The seasonality of our natural gas liquids businesses has a significant effect on our cash flows from operating activities. The changes in our operating assets and liabilities caused by the seasonality of our retail and wholesale natural gas liquids businesses also have a significant impact on our net cash flows from operating activities. Increases in natural gas liquids prices will tend to result in reduced operating cash flows due to the need to use more cash to fund increases in inventories, and price decreases tend to increase our operating cash flow due to lower cash requirements to fund increases in inventories.

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        In general, our operating cash flows are at their lowest levels during our first and second fiscal quarters, or the six months ending September 30, when we experience operating losses or lower operating income as a result of lower volumes of natural gas liquids sales and when we are building our inventory levels for the upcoming heating season. Our operating cash flows are generally greatest during our third and fourth fiscal quarters, or the six months ending March 31, when our operating income levels are highest and customers pay for natural gas liquids consumed during the heating season months. We borrow under our Revolving Credit Facility to supplement our operating cash flows as necessary during our first and second quarters.

        The growth in our operating cash flows over the period from fiscal 2012 to fiscal 2014 was driven primarily by increased operating activity resulting from acquisitions. Changes in working capital due to changes in the timing of cash receipts and payments can have a significant impact on cash flows from operations. During fiscal 2013 and fiscal 2014, our cash outflows from investing activities included the purchase of working capital in business combinations, a portion of which has benefitted (or will benefit) cash flows from operations as the working capital is recovered. Our operating cash flows during the year ended March 31, 2012 included the sale of $30.3 million of inventory (net of purchases). This was due in part to our acquisition of assets from SemStream on November 1, 2011, in which we acquired $104.2 million of inventory. The cash paid to complete the SemStream transaction is included within cash outflows from investing activities.

        Investing Activities.    Our cash flows from investing activities are primarily impacted by our capital expenditures. In periods where we are engaged in significant acquisitions, we will generally realize negative cash flows in investing activities, which, depending on our cash flows from operating activities, may require us to increase the borrowings under our Revolving Credit Facility. During the six months ended September 30, 2014, we paid $82.9 million for capital expenditures. Of this amount, $65.7 million represented expansion capital and $17.2 million represented maintenance capital. During the six months ended September 30, 2013, we paid $67.4 million for capital expenditures. Of this amount, $52.4 million represented expansion capital and $15.0 million represented maintenance capital. During the six months ended September 30, 2014, we paid (i) $554.5 million in the TransMontaigne acquisition, (ii) $82.9 million to acquire water disposal facilities, (iii) $15.0 million to acquire an interest in a water supply company, and (iv) $6.4 million to acquire retail propane businesses. During the six months ended September 30, 2013, we completed a number of business combinations for which we paid $392.6 million of cash, net of cash acquired, on a combined basis. During the year ended March 31, 2014, we completed a number of business combinations for which we paid $1.3 billion of cash, net of cash acquired, on a combined basis. Also during the year ended March 31, 2014, we paid $165.1 million for capital expenditures, which related primarily to water disposal and natural gas liquids terminal assets. Of this amount, $132.9 million represented expansion capital and $32.2 million represented maintenance capital. During the year ended March 31, 2014, we used $36.0 million of investing cash outflows from commodity derivatives and generated $24.7 million of investing cash inflows from the sale of long-lived assets. During the year ended March 31, 2013, we completed our merger with High Sierra, for which we paid $239.3 million, net of cash acquired. Also during the year ended March 31, 2013, we completed 12 other acquisitions, for which we paid $251.5 million of cash, net of cash acquired, on a combined basis. Also during the year ended March 31, 2013, we paid $72.5 million for capital expenditures in addition to the acquisitions of businesses. Of this amount, $58.7 million represented expansion capital and $13.8 million represented maintenance capital. During the year ended March 31, 2013, we generated $11.6 million of investing cash inflows from commodity derivatives and $5.1 million of investing cash inflows from the sale of long-lived assets. During the year ended March 31, 2012, we completed four significant acquisitions and several smaller acquisitions. We paid a combined cash amount of $297.4 million to complete these acquisitions.

        Financing Activities.    Changes in our cash flow from financing activities include advances from and repayments on our revolving credit facilities, either to fund our operating or investing requirements. In

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periods where our cash flows from operating activities are reduced (such as during our first and second quarters), we may fund the cash flow deficits through our Working Capital Facility. During the six months ended September 30, 2014, we borrowed $175.5 million on our revolving credit facilities (net of repayments). During the six months ended September 30, 2014, we issued the 2019 Notes for $400.0 million. During the six months ended September 30, 2014, we received net proceeds of $370.4 million from the sale of our common units. During the six months ended September 30, 2013, we borrowed $168.5 million on our Revolving Credit Facility (net of repayments). During the six months ended September 30, 2013, we received net proceeds of $415.1 million from the sale of our common units. During the year ended March 31, 2014, we borrowed $444.5 million on our Revolving Credit Facility (net of repayments) and issued $450.0 million of Unsecured Notes. During the year ended March 31, 2014, we paid $24.6 million of debt issuance costs. During the year ended March 31, 2013, we borrowed $263.5 million on our revolving credit facilities (net of repayments) and issued $250.0 million of Senior Notes. During the year ended March 31, 2013, we paid $20.2 million of debt issuance costs. During the year ended March 31, 2012, we borrowed $149.0 million on our revolving credit facilities (net of repayments), primarily to fund acquisitions.

        Cash flows from financing activities include proceeds from sales of equity. During the year ended March 31, 2014, we completed three equity issuances for which we received net proceeds of $650.2 million on a combined basis.

        Cash flows from financing activities also include distributions paid to owners. We expect our distributions to our partners to increase in future periods under the terms of our partnership agreement. Based on the number of common units outstanding at September 30, 2014 (exclusive of unvested restricted units issued pursuant to employee and director compensation programs), if we made distributions equal to our minimum quarterly distribution of $0.3375 per unit ($1.35 annualized), total distributions would equal $29.9 million per quarter ($119.7 million per year). To the extent our cash flows from operating activities are not sufficient to finance our required distributions, we may be required to increase the borrowings under our Working Capital Facility.

        The following table summarizes the distributions declared since our IPO:

Date Declared
  Record Date   Date Paid   Amount
Per Unit
  Amount Paid To
Limited Partners
  Amount Paid To
General Partner
 
 
   
   
   
  (in thousands)
  (in thousands)
 

July 25, 2011

  August 3, 2011   August 12, 2011   $ 0.1669   $ 2,467   $ 3  

October 21, 2011

  October 31, 2011   November 14, 2011     0.3375     4,990     5  

January 24, 2012

  February 3, 2012   February 14, 2012     0.3500     7,735     10  

April 18, 2012

  April 30, 2012   May 15, 2012     0.3625     9,165     10  

July 24, 2012

  August 3, 2012   August 14, 2012     0.4125     13,574     134  

October 17, 2012

  October 29, 2012   November 14, 2012     0.4500     22,846     707  

January 24, 2013

  February 4, 2013   February 14, 2013     0.4625     24,245     927  

April 25, 2013

  May 6, 2013   May 15, 2013     0.4775     25,605     1,189  

July 25, 2013

  August 5, 2013   August 14, 2013     0.4938     31,725     1,739  

October 23, 2013

  November 4, 2013   November 14, 2013     0.5113     35,908     2,491  

January 23, 2014

  February 4, 2014   February 14, 2014     0.5313     42,150     4,283  

April 24, 2014

  May 5, 2014   May 15, 2014     0.5513     43,737     5,754  

July 24, 2014

  August 4, 2014   August 14, 2014     0.5888     52,036     9,481  

October 23, 2014

  November 4, 2014   November 14, 2014     0.6088     53,902     11,141  

        Distributions to noncontrolling interest partners are primarily comprised of distributions that TLP is required to make within 45 days after the end of each quarter to its unitholders as of the record date. To the extent TLP's cash flows from operating activities are not sufficient to finance its required distributions, it may be required to increase borrowings under the TLP Credit Facility.

        On May 5, 2011, we made a distribution of $3.9 million from available cash to our general partner and common unitholders at March 31, 2011. Also in May 2011, we used $65.0 million of the proceeds from our IPO to repay advances under our previous credit facility.

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Contractual Obligations

        The following table summarizes our contractual obligations at September 30, 2014 for our fiscal years ending thereafter:

 
   
  Six Months
Ending
March 31,
2015
  Years Ending March 31,    
 
 
  Total   2016   2017   2018   Thereafter  
 
  (in thousands)
 

Principal payments on long-term debt—

                                     

Expansion capital borrowings

  $ 137,000   $   $   $   $   $ 137,000  

Working capital borrowings

    942,500                     942,500  

2019 Notes

    400,000                     400,000  

2021 Notes

    450,000                     450,000  

2022 Notes

    250,000                 25,000     225,000  

TLP Credit Facility

    252,000         252,000              

Other long-term debt

    10,913     2,345     3,128     2,362     1,459     1,619  

Interest payments on long-term debt—

                                     

Revolving credit facility(1)

    115,595     14,097     28,194     28,194     28,194     16,916  

2019 Notes

    102,500     10,250     20,500     20,500     20,500     30,750  

2021 Notes

    232,031     15,469     30,938     30,938     30,938     123,748  

2022 Notes

    91,438     8,313     16,625     16,625     16,209     33,666  

TLP Credit Facility(1)

    5,868     3,352     2,516              

Other long-term debt

    655     220     206     123     78     28  

Letters of credit

    209,188                     209,188  

Future minimum lease payments under noncancelable operating leases

    507,354     71,007     106,384     88,666     74,265     167,032  

Future minimum throughput payments under noncancelable agreements(2)

    441,168     41,822     95,050     82,916     62,565     158,815  

Fixed-price commodity purchase commitments

    102,000     101,344     656              

Index-price commodity purchase commitments(3)

    984,872     950,613     34,259              
                           

Total contractual obligations

  $ 5,235,082   $ 1,218,832   $ 590,456   $ 270,324   $ 259,208   $ 2,896,262  
                           
                           

Natural gas liquids gallons under fixed-price purchase commitments (thousands)(4)

    88,574     87,944     630              

Natural gas liquids gallons under index-price purchase commitments (thousands)(4)

    528,459     520,243     8,216              

Crude oil barrels under index-price purchase commitments (thousands)(4)

    4,437     4,079     358              

(1)
The estimated interest payments on our revolving credit facilities are based on principal and letters of credit outstanding at September 30, 2014. See Note 7 to our condensed consolidated financial statements included in this Quarterly Report for additional information on our revolving credit facilities.

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(2)
At September 30, 2014, we had agreements with crude oil and refined products pipeline operators obligating us to minimum throughput payments in exchange for pipeline capacity commitments.

(3)
Index prices are based on a forward price curve at September 30, 2014. A theoretical change of $0.10 per gallon in the underlying commodity price at September 30, 2014 would result in a change of $52.8 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel in the underlying commodity price at September 30, 2014 would result in a change of $4.4 million in the value of our index-price crude oil purchase commitments.

(4)
At September 30, 2014, we had fixed-price and index-price sales contracts for 278.4 million and 370.6 million gallons of natural gas liquids, respectively. At September 30, 2014, we had index-price sales contracts for 3.9 million barrels of crude oil.

Off-Balance Sheet Arrangements

        We do not have any off balance sheet arrangements other than the operating leases described in Note 10 to our audited consolidated financial statements included elsewhere in this prospectus and in Note 9 to our unaudited condensed consolidated financial statements included elsewhere in this prospectus.

Environmental Legislation

        Please see "Business—Government Regulation—Greenhouse Gas Regulation" for a discussion of proposed environmental legislation and regulations that, if enacted, could result in increased compliance and operating costs. However, at this time we cannot predict the structure or outcome of any future legislation or regulations or the eventual cost we could incur in compliance.

Trends

Crude Oil Logistics

        Crude oil prices fluctuate widely due to changes in supply and demand conditions. The opportunity to generate revenues in our crude oil logistics business is heavily influenced by the volume of crude oil being produced. Currently, production of crude oil in North America is high, but changes in the level of production could impact our ability to generate revenues in the future.

        The spreads between the prices of crude oil in different locations can also fluctuate widely. If these price differences are wide, we are able to generate increased margins by transporting crude oil from lower-price markets to higher-price markets. During the six months ended September 30, 2013, spreads remained narrow. When price differences between markets are reduced, it is necessary to renegotiate price terms with producers and to not fully utilize our transportation fleet until this process has been completed and margins have improved. Crude oil prices declined steadily during the three months ended September 30, 2014. Declining prices can have an adverse impact on product margins, due to delays between when product is purchased and when it is sold. If prices continue to decline, low prices could have an adverse effect on the level of crude oil production. During the year ended March 31, 2014, spreads narrowed considerably, which had a significant impact on our operations in the Rocky Mountain and South Texas regions. During the year ended March 31, 2013, the spread between crude oil prices in the mid-continent region and crude oil prices in south Texas widened, which gave us the opportunity to generate favorable margins by transporting crude oil from one region to the other.

Water Solutions

        Our opportunity to earn revenues in our water solutions business is based on the level of production of natural gas and crude oil in the areas where our facilities are located. Currently,

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production levels are increasing, and we are expanding our operations in Colorado and Texas to meet this demand.

        Crude oil prices declined steadily during the three months ended September 30, 2014. A portion of our revenues are generated from the sale of recovered hydrocarbons, and therefore crude oil prices impact the revenues of our water solutions segment. If crude oil prices continue to decline, the low prices could have an adverse effect on the level of crude oil production.

        During the year ended March 31, 2014, we completed three separate acquisitions of water solutions businesses with operations in Texas. As a result, the geographic mix of our water solutions segment has changed, and we expect a greater share of the revenues from this segment to be generated from our operations in the Permian and Eagle Ford Basins in Texas than in the past.

        During the year ended March 31, 2014, the revenues of our water solutions segment were lower than our expectations and the operating expenses of our water solutions segment were higher than our expectations. This related primarily to our operations in the Eagle Ford Basin in Texas, which were obtained through several acquisitions during the year ended March 31, 2014.

Liquids

        The volumes we sell in our wholesale natural gas liquids business are heavily dependent on the demand for propane and butane, which is influenced by weather conditions. The margins we generate in our wholesale natural gas liquids business are influenced by changes in prices over the course of a year. During years when demand is higher during the winter months, we have the opportunity to utilize our storage assets to increase margins.

        Demand for natural gas liquids was high during the recent winter, due to cold weather conditions. Demand continued to be high during the six months ended September 30, 2014, as customers sought to replenish their supplies of natural gas liquids that had been depleted during the winter. As a result, sales volumes and prices were higher during the six months ended September 30, 2014 than during the corresponding period in the prior year. However, our product margin per gallon sold was lower during the six months ended September 30, 2014 than during the corresponding period in the prior year, as we began the year with inventory that had a high cost basis as a result of the high demand during the previous winter.

        We use a weighted-average inventory costing method for our wholesale propane inventory, with the costing pools segregated based on the location of the inventory. During periods of declining prices, our margins are reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher.

        One of our business strategies is to purchase and store inventory during the warmer months for sale during the winter months. We seek to lock in a margin on inventory held in storage through back-to-back purchases and sales, fixed-price forward sale commitments, and financial derivatives. We also have contracts whereby we have committed to purchase ratable volumes each month at index prices. We seek to manage the price risk associated with these contracts primarily by selling the inventory immediately after it is received. When we sell product, we record the cost of the sale at the average cost of all inventory at that location, which may include inventory stored for sale in the future. During periods of rising prices, this can result in greater margins on these sales. During periods of falling prices, this can result in negative margins on these sales.

        Weather conditions during the recent winter season were colder than normal. As a result, the demand for natural gas liquids increased considerably, which had a favorable impact on our sales volumes. The demand has also resulted in increases to market prices for natural gas liquids. This has had a favorable impact on product margins, based on the fact that we purchased inventory when prices, and therefore our average cost of inventory, were lower than when we sold the inventory.

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Retail Propane

        The volumes we sell in our retail propane business are heavily dependent on weather conditions, as cold weather significantly increases customer demand for propane. During times of lower propane prices, margins per gallon typically increase. During times of higher propane prices, margins per gallon typically decrease. Weather conditions during the 2013 to 2014 winter season were colder than normal. As a result, the demand for natural gas liquids increased considerably, which had a favorable impact on our sales volumes. The demand also resulted in increases to market prices for natural gas liquids. This had a favorable impact on product margins, based on the fact that we purchased inventory when prices, and therefore our average cost of inventory, were lower than when we sold the inventory. The sharp rise in prices may increase the collectability risk of accounts receivable, and the recent high prices may create downward pressure on future demand, as some customers may invest in making their homes more energy efficient or may take other steps to reduce their need for propane.

Refined Products and Renewables

        The spread between the prices of ethanol in different locations can fluctuate widely. If these price differences are high, we are able to generate increased margins by transporting ethanol from lower-price markets to higher-price markets. During the last few months of the fiscal year ended March 31, 2014, the spread between ethanol prices in different markets widened, which gave us the opportunity to generate favorable margins by transporting ethanol from one region to the other. During April 2014, ethanol price spreads between regions narrowed considerably.

        Demand for biodiesel is driven in part by EPA mandates for the volume of biodiesel that refiners and blenders must use. The EPA has not yet issued its final mandate for 2014 biodiesel usage. The current uncertainty regarding the requirements has reduced the demand for biodiesel, which has had an adverse impact on biodiesel prices and volumes.

Recent Accounting Pronouncement

        In April 2014, the Financial Accounting Standards Board issued an Accounting Standards Update that changes the criteria for reporting discontinued operations. Under the new standard, a disposal of part of an entity is not classified as a discontinued operation unless the disposal represents a strategic shift that will have a major effect on an entity's operations and financial results. We adopted the new standard during the fiscal year ended March 31, 2014.

        As described in Note 14 to our audited consolidated financial statements included elsewhere in this prospectus, during the year ended March 31, 2014, we sold our compressor leasing business and wound down our natural gas marketing business. These actions do not represent a strategic shift that had a major effect on our operations, and do not meet the criteria under the new accounting standard for these businesses to be reported as discontinued operations.

        In May 2014, the Financial Accounting Standard Board issued Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers." ASU No. 2014-09 will replace most existing revenue recognition guidance in GAAP. The core principle of this ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU is effective for the Partnership beginning April 1, 2017, and allows for both retrospective and prospective methods of adoption. We are in the process of determining the method of adoption and assessing the impact of this ASU on our consolidated financial statements.

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Critical Accounting Policies

        The preparation of financial statements and related disclosures in compliance with GAAP requires the selection and application of appropriate accounting principles to the relevant facts and circumstances of the Partnership's operations and the use of estimates made by management. We have identified the following accounting policies that are most important to the portrayal of our financial condition and results of operations. Changes in these policies could have a material effect on the financial statements.

        The application of these accounting policies necessarily requires subjective or complex judgments regarding estimates and projected outcomes of future events that could have a material effect on our financial statements.

Revenue Recognition

        We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. We record our terminaling, storage and service revenues at the time the service is performed and we record tank and other rentals over the term of the lease. Revenues for our water solutions business are recognized upon receipt of the wastewater at our disposal facilities.

        We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. Amounts billed to customers for shipping and handling costs are included in revenues in the consolidated statements of operations.

        We enter into certain contracts whereby we agree to purchase product from a counterparty and to sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into concurrently and are entered into in contemplation of each other, we record the revenues for these transactions net of cost of sales.

Impairment of Long-Lived Assets

        Goodwill is subject to at least an annual assessment for impairment. We perform our annual assessment of impairment during the fourth quarter of our fiscal year, and more frequently if circumstances warrant. To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting unit exceeds its carrying amount. We completed the assessment of each of our reporting units and determined it was more likely than not that no impairment existed for the year ended March 31, 2014. The assessment of the value of our reporting units requires us to make certain assumptions relating to future operations. When evaluating operating performance, various factors are considered, such as current and changing economic conditions and the commodity price environment, among others. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge.

        We evaluate property, plant and equipment and amortizable intangible assets for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is less than its carrying value.

        We evaluate equity method investments for impairment when we believe the current fair value may be less than the carrying amount. We record impairments of equity method investments if we believe the decline in value is other than temporary.

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Asset Retirement Obligations

        We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value can be made. In order to determine the fair value of such a liability, we must make certain estimates and assumptions including, among other things, projected cash flows, the estimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time. We have recorded a liability of $2.7 million at September 30, 2014. This liability is related to wastewater disposal facilities and crude oil facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

        In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certain other assets. We do not believe the present value of these asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of our facilities, is material to our consolidated financial position or results of operations.

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment

        Depreciation expense represents the systematic write-off of the cost of our property, plant and equipment, net of residual or salvage value (if any), to the results of operations for the quarterly and annual periods during which the assets are used. We depreciate the majority of our property, plant and equipment using the straight-line method, which results in our recording depreciation expense evenly over the estimated life of the individual asset. The estimate of depreciation expense requires us to make assumptions regarding the useful economic lives and residual values of our assets. At the time we acquire and place our property, plant and equipment in service, we develop assumptions about the lives and residual values of such assets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our depreciation expense prospectively. Examples of such circumstances include changes in laws and regulations that limit the estimated economic life of an asset, changes in technology that render an asset obsolete, or changes in expected salvage values.

Amortization of Intangible Assets

        Amortization expense represents the systematic write-off of the cost of our amortizable intangible assets to the results of operations for the quarterly and annual periods during which the assets are used. We amortize the majority of these intangible assets using the straight-line method, which results in our recording amortization expense evenly over the estimated life of the individual asset. The estimate of amortization expense requires us to make assumptions regarding the useful economic lives of our assets. At the time we acquire intangible assets, we develop assumptions about the lives of such assets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our amortization expense prospectively. Examples of such circumstances include changes in customer attrition rates and changes in laws and regulations that could limit the estimated economic life of an asset.

Business Combinations

        We have made in the past, and expect to make in the future, acquisitions of other businesses. We record business combinations using the "acquisition method," in which the assets acquired and liabilities assumed are recorded at their estimated fair values. Fair values of assets acquired and liabilities assumed are based upon available information and may involve us engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant

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business judgment. We must also identify and include in the allocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property, plant and equipment and intangible assets, including those with indefinite lives. The estimates also include the fair value of contracts including commodity purchase and sale agreements, storage and transportation contracts, and employee compensation commitments. The excess of the purchase price over the net fair value of acquired assets over the assumed liabilities is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Generally, we have up to one year from the acquisition date to finalize the identification and valuation of assets acquired and liabilities assumed. The impact of subsequent changes to the identification of assets and liabilities may require retrospective adjustments to our previously-reported consolidated financial position and results of operations.

Inventory

        Our inventory consists primarily of crude oil, natural gas liquids, refined products, ethanol, and biodiesel. The market values of these commodities change on a daily basis as supply and demand conditions change. We value our inventory using the weighted-average cost and first-in first-out methods. At the end of each fiscal year, we also perform a "lower of cost or market" analysis; if the cost basis of the inventory would not be recoverable based on market prices at the end of the year, we reduce the book value of the inventory to the recoverable amount. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business to sell the inventory in retail markets. When performing this analysis during interim periods within a fiscal year, accounting standards do not require us to record a lower of cost or market write-down if we expect the market values to recover by our fiscal year end of March 31. We are unable to control changes in the market value of these commodities and are unable to determine whether write-downs will be required in future periods. In addition, write-downs at interim periods could be required if we cannot conclude that market values will recover sufficiently by our fiscal year end.

Equity-Based Compensation

        Our general partner has granted certain restricted units to employees and directors under a long-term incentive plan. These units vest in tranches, subject to the continued service of the recipients.

        We record the expense for the first tranche of each award on a straight-line basis over the period beginning with the grant date of the awards and ending with the vesting date of the tranche. We record the expense for succeeding tranches over the period beginning with the vesting date of the previous tranche and ending with the vesting date of the tranche.

        At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using the closing price of our common units on the New York Stock Exchange on the balance sheet date, adjusted to reflect the fact that the holders of the unvested units are not entitled to distributions during the vesting period. We estimate the impact of the lack of distribution rights during the vesting period using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth.

        We report unvested units as liabilities on our consolidated balance sheets. When units vest and are issued, we record an increase to equity.

Amortization of Intangible Assets

        Amortization expense represents the systematic write-off of the cost of our amortizable intangible assets to the results of operations for the quarterly and annual periods during which the assets are

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used. We amortize the majority of these intangible assets using the straight-line method, which results in us recording amortization expense evenly over the estimated life of the individual asset. The estimate of amortization expense requires us to make assumptions regarding the useful economic lives of our assets. At the time we acquire intangible assets, we develop assumptions about the useful economic lives of such assets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our amortization expense prospectively. Examples of such circumstances include changes in customer attrition rates and changes in laws and regulations that could limit the estimated economic life of an asset.

Business Combinations

        We have made in the past, and expect to make in the future, acquisitions of other businesses. We record business combinations using the "acquisition method," in which the assets acquired and liabilities assumed are recorded at their estimated fair values. Fair values of assets acquired and liabilities assumed are based upon available information and may involve us engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identify and include in the allocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property, plant and equipment and intangible assets, including those with indefinite lives. The estimates also include the fair value of contracts including commodity purchase and sale agreements, storage and transportation contracts, and employee compensation commitments. The excess of the purchase price over the net fair value of acquired assets and assumed liabilities is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination. The impact of subsequent changes to the identification of assets and liabilities may require retrospective adjustments to our previously-reported consolidated financial position and results of operations.

Inventories

        Our inventories consist primarily of crude oil, natural gas liquids, refined products, ethanol, and biodiesel. The market values of these commodities change on a daily basis as supply and demand conditions change. We value our inventories at the lower of cost or market, with cost determined using either the weighted-average cost or the first in, first out (FIFO) methods, including the cost of transportation and storage. At the end of each fiscal year, we also perform a "lower of cost or market" analysis; if the cost basis of the inventories would not be recoverable based on market prices at the end of the year, we reduce the book value of the inventories to the recoverable amount. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business to sell the inventory in retail markets. When performing this analysis during interim periods within a fiscal year, accounting standards do not require us to record a lower of cost or market write-down if we expect the market values to recover by our fiscal year end of March 31. We are unable to control changes in the market value of these commodities and are unable to determine whether write-downs will be required in future periods. In addition, write-downs at interim periods could be required if we cannot conclude that market values will recover sufficiently by our fiscal year end.

Equity-Based Compensation

        Our general partner has granted certain restricted units to employees and directors under a long-term incentive plan. These units vest in tranches, subject to the continued service of the recipients.

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        We record the expense for the first tranche of each award on a straight-line basis over the period beginning with the grant date of the awards and ending with the vesting date of the tranche. We record the expense for succeeding tranches over the period beginning with the vesting date of the previous tranche and ending with the vesting date of the tranche.

        At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using the closing price of our common units on the New York Stock Exchange on the balance sheet date, adjusted to reflect the fact that the holders of the unvested units are not entitled to distributions during the vesting period. We estimate the impact of the lack of distribution rights during the vesting period using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth.

        We report unvested units as liabilities on our condensed consolidated balance sheets. When units vest and are issued, we record an increase to equity.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

        At September 30, 2014, a significant portion of our long-term debt is variable-rate debt. Changes in interest rates impact the interest payments of our variable-rate debt but generally do not impact the fair value of the liability. Conversely, changes in interest rates impact the fair value of the fixed-rate debt but do not impact its cash flows.

        Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At September 30, 2014, we had $1.1 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 1.91%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.3 million, based on borrowings outstanding at September 30, 2014.

        The TLP Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At September 30, 2014, TLP had $252.0 million of outstanding borrowings under the TLP Credit Facility at a rate of 2.66%. A change in interest rates of 0.125% would result in an increase or decrease in TLP's annual interest expense of $0.3 million, based on borrowings outstanding at September 30, 2014. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.2 million on the $922.0 million of outstanding borrowings on the Revolving Credit Facility at March 31, 2014.

Commodity Price and Credit Risk

        Our operations are subject to certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that the market value of crude oil, propane, and other natural gas liquids will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract.

        As is customary in the crude oil industry, we generally receive payment from customers for sales of crude oil on a monthly basis. As a result, receivables from individual customers in our crude oil logistics segment are generally higher than the receivables from customers in our other segments.

        Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, restrictions on product liftings, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions, as deemed appropriate. The principal counterparties associated with our operations at September 30, 2014 were retailers, resellers, energy marketers, producers, refiners and dealers.

        The natural gas liquids and crude oil industries are "margin-based" and "cost-plus" businesses in which gross profits depend on the differential of sales prices over supply costs. As a result, our profitability may be impacted by changes in wholesale prices of natural gas liquids and crude oil. When there are sudden and sharp increases in the wholesale cost of natural gas liquids and crude oil, we may not be able to pass on these increases to our customers through retail or wholesale prices. Natural gas liquids and crude oil are commodities and the price we pay for them can fluctuate significantly in response to supply or other market conditions. We have no control over supply or market conditions. In addition, the timing of cost increases can significantly affect our realized margins. Sudden and extended wholesale price increases could reduce our gross margins and could, if continued over an

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extended period of time, reduce demand by encouraging end users to conserve or convert to alternative energy sources.

        We engage in derivative financial and other risk management transactions, including various types of forward contracts and financial derivatives, to reduce the effect of price volatility on our product costs, protect the value of our inventory positions, and to help ensure the availability of product during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes when we have a matching purchase commitment from our wholesale and retail customers. We may experience net unbalanced positions from time to time. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio.

        Although we use derivative commodity instruments to reduce the market price risk associated with forecasted transactions, we have not accounted for such derivative commodity instruments as hedges. We record the changes in fair value of these derivative commodity instruments within cost of sales. The following table summarizes the hypothetical impact on the fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands):

 
  Increase
(Decrease) To
Fair Value
 

Crude oil (crude oil logistics segment)

  $ (3,699 )

Crude oil (water solutions segment)

    (10,595 )

Propane (liquids segment)

    5,519  

Other products (liquids segment)

    (930 )

Refined products (refined products and renewables segment)

    (51,414 )

Renewables (refined products and renewables segment)

    346  

Fair Value

        We use observable market values for determining the fair value of our derivative instruments. In cases where actively quoted prices are not available, other external sources are used which incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis.

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MANAGEMENT

Board of Directors of our General Partner

        NGL Energy Holdings LLC, our general partner, manages our operations and activities on our behalf through its directors and executive officers, which executive officers are also officers of our operating company. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. The NGL Energy GP Investor Group appoints all members to the board of directors of our general partner.

        The board of directors of our general partner currently has eleven members. The board of directors of our general partner has determined that Mr. Kneale, Mr. Cropper, and Mr. Guderian satisfy the New York Stock Exchange ("NYSE") and SEC independence requirements. The NYSE does not require a listed publicly traded limited partnership like us to have a majority of independent directors on the board of directors of our general partner. In addition, we are not required to have a nominating and corporate governance committee.

        In evaluating director candidates, the NGL Energy GP Investor Group assesses whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the ability of the board of directors of our general partner to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties. Our general partner has no minimum qualifications for director candidates. In general, however, the NGL Energy GP Investor Group reviews and evaluates both incumbent and potential new directors in an effort to achieve diversity of skills and experience among the directors of our general partner and in light of the following criteria:

        Although our general partner does not have a formal policy in regard to the consideration of diversity in identifying director nominees, qualified candidates for nomination to the board are considered without regard to race, color, religion, gender, ancestry or national origin.

Directors and Executive Officers

        Directors of our general partner are appointed by the NGL Energy GP Investor Group and hold office until their successors have been duly elected and qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion

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of, the board of directors of our general partner. The following table shows information regarding the current directors of our general partner and our executive officers.

Name
  Age   Position with NGL Energy Holdings LLC
H. Michael Krimbill     60   Chief Executive Officer and Director
Atanas H. Atanasov     41   Chief Financial Officer and Treasurer
James J. Burke     58   President, NGL Energy Partners and Director
Shawn W. Coady     52   President and Chief Operating Officer, Retail Division and Director
Todd M. Coady     56   Vice President, Administration
David C. Kehoe     55   Executive Vice President, NGL—Crude Logistics
Patrice A. Lemon     53   Senior Vice President, Accounting
Vincent J. Osterman     57   President, Eastern Retail Propane Operations and Director
Stephen L. Cropper     64   Director
Bryan K. Guderian     54   Director
James C. Kneale     62   Director
John T. Raymond     43   Director
Patrick Wade     44   Director

        H. Michael Krimbill.    Mr. Krimbill has served as our Chief Executive Officer since October 2010 and as a member of the board of directors of our general partner since its formation in September 2010. From February 2007 through September 2010, Mr. Krimbill managed private investments. Mr. Krimbill was the President and Chief Financial Officer of Energy Transfer Partners, L.P. from 2004 until his resignation in January 2007. Mr. Krimbill joined Heritage Propane Partners, L.P., the predecessor of Energy Transfer Partners, L.P., as Vice President and Chief Financial Officer in 1990. Mr. Krimbill was President of Heritage Propane Partners, L.P. from 1999 to 2000 and President and Chief Executive Officer of Heritage Propane Partners, L.P. from 2000 to 2005. Mr. Krimbill also served as a director of Energy Transfer Equity, the general partner of Energy Transfer Partners, L.P., from 2000 to January 2007. Mr. Krimbill is also currently a member of the board of directors of Pacific Commerce Bank.

        Mr. Krimbill brings leadership, oversight and financial experience to the board. Mr. Krimbill provides expertise in managing and operating a publicly traded partnership, including substantial expertise in successfully acquiring and integrating propane and midstream businesses. Mr. Krimbill also brings financial expertise to the board, including through his prior service as a chief financial officer. As a director for other public companies, Mr. Krimbill also provides cross board experience.

        Atanas H. Atanasov.    Mr. Atanasov was appointed as our Chief Financial Officer in May 2013. Mr. Atanasov joined our management team in November 2011, and previously served as our Senior Vice President of Finance and Treasurer. Prior to joining NGL, Mr. Atanasov spent nine years at GE Capital, working in lending and leveraged equity. Prior to GE Capital, he was with The Williams Companies, Inc. Mr. Atanasov is a Certified Public Accountant and holds an M.B.A. from the University of Tulsa and a B.S. in Accounting from Oral Roberts University.

        James J. Burke.    Mr. Burke serves as the President of NGL Energy Partners and joined the board of directors of our general partner in 2012. Mr. Burke was one of High Sierra's co-founders and served as Chairman of the High Sierra board and President and Chief Executive Officer of the High Sierra general partner since September 2010. From July 2004 to September 2010, Mr. Burke was the High Sierra general partner's Managing Director. Mr. Burke, along with three other entrepreneurs, co-founded Petro Source Partners, LP, where he ran six business units throughout the United States and Canada for the company over a 17-year span. Prior to that, Mr. Burke served as Manager of Crude Oil Acquisitions at Asamera Oil (United States) Inc. from 1981 to 1984. Mr. Burke began his career as a Crude Oil Representative at Permian Corporation, where he worked from 1978 to 1981. Mr. Burke

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also serves as the Managing Director of Impact Energy Services, LLC. Mr. Burke received his B.S. from University of Colorado in 1978.

        Shawn W. Coady.    Dr. Coady has served as our President and Chief Operating Officer, Retail Division, since April 2012 and previously served as our Co-President and Chief Operating Officer, Retail Division from October 2010 through April 2012. Dr. Coady has also served as a member of the board of directors of our general partner since its formation in September 2010. Dr. Coady has served as an officer of Hicks Oils & Hicksgas, Incorporated, or HOH, since March 1989. HOH contributed its propane and propane related assets to Hicks LLC, and the membership interests in Hicks LLC were contributed to us as part of our formation transactions. Dr. Coady was an executive officer of Bachtold Brothers, Incorporated, a family owned company, when it filed for Chapter 7 bankruptcy protection in October 2005. Dr. Coady was also the President of Gifford from March 1989 until the membership interests in Gifford were contributed to us as part of our formation transactions. Dr. Coady has served as a director and as a member of the executive committee of the Illinois Propane Gas Association since 2004. Dr. Coady has also served as the Illinois state director of the National Propane Gas Association since 2004. Dr. Coady has a B.A. in Chemistry from Emory University and an O.D. from the University of Houston. Dr. Coady is the brother of Mr. Coady.

        Dr. Coady brings valuable management and operational experience to the board. Dr. Coady has over 25 years of experience in the retail propane industry, and provides expertise in both acquisition and organic growth strategies. Dr. Coady also provides insight into developments and trends in the propane industry through his leadership roles in national and state propane gas associations.

        Todd M. Coady.    Mr. Coady has served as our Vice President, Administration since April 2012 and previously served as our Co-President, Retail Division from October 2010 through April 2012. Mr. Coady has served as an officer of HOH since March 1989. HOH contributed its propane and propane related assets to Hicks LLC, and the membership interests in Hicks LLC were contributed to us as part of our formation transactions. Mr. Coady was also the Vice President of Gifford from March 1989 until the membership interests in Gifford were contributed to us as part of our formation transactions. Mr. Coady was an executive officer of Bachtold Brothers, Incorporated, a family owned company, when it filed for Chapter 7 bankruptcy protection in October 2005. Mr. Coady has a B.S. in Chemical Engineering from Cornell University and an M.B.A. from Rice University. Mr. Coady is the brother of Dr. Coady.

        David C. Kehoe.    Mr. Kehoe serves as the Executive Vice President of the NGL — Crude Logistics segment. Mr. Kehoe joined our management team through our June 2012 merger with High Sierra. Mr. Kehoe has served on High Sierra's management team since 2007. Prior to that, Mr. Kehoe held various leadership positions with Petro Source Partners, LP from 1989 to 2007.

        Patrice A. Lemon.    Ms. Lemon has served as our Senior Vice President of Accounting since May 2012. Ms. Lemon previously served several roles in accounting and SEC reporting with Energy Transfer Partners, L.P. and Heritage Propane Partners, L.P. from March 2001 through May 2012. In March 2001, Ms. Lemon joined Heritage Propane Partners, L.P., the predecessor of Energy Transfer Partners, L.P., as the Manager of Financial Reporting. Ms. Lemon's most recent role prior to joining NGL was the Director of Financial Reporting and Controller with Heritage Propane Partners, L.P. For ten years prior to joining Heritage Propane Partners, L.P., Ms. Lemon worked as an audit manager for a regional public accounting firm in Montana. Ms. Lemon received a B.A. in Accounting from Carroll College of Helena, Montana.

        Vincent J. Osterman.    Mr. Osterman has served as the President of Osterman Associated Companies, which contributed the assets of its propane operations to us on October 3, 2011, since August 1987. Mr. Osterman has served as President of our Eastern Retail Propane Operations and as a member of the board of directors of our general partner since October 2011. Mr. Osterman also serves

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as a director of the National Propane Gas Association, Propane Gas Association of New England, Energi Holdings, Inc., and the Board of Advisors of the Gaudette Insurance Agency.

        With his long tenure as President of the Osterman Associated Companies, Mr. Osterman brings valuable executive and operational experience in the retail propane businesses to the board. Mr. Osterman also provides insight into developments and trends in the propane industry through his leadership roles in industry associations.

        Stephen L. Cropper.    Mr. Cropper joined the board of directors of our general partner in June 2011. Mr. Cropper held various positions during his 25-year career at The Williams Companies, Inc., including serving as the President and Chief Executive Officer of Williams Energy Services, a Williams operating unit involved in various energy-related businesses, until his retirement in 1998. Mr. Cropper served as a director of Energy Transfer Partners L.P. from 2000 through 2005. Since Mr. Cropper's retirement from The Williams Companies, Inc. in 1998, he has been a consultant and private investor and also served as a director of Sunoco Logistics Partners, L.P., NRG Energy, Inc., and Berry Petroleum Company.

        Mr. Cropper brings substantial experience in the energy business and in the marketing of energy products to the board. With his significant management and governance experience, Mr. Cropper provides important skills in identifying, assessing and addressing various business issues. As a director for other public companies, Mr. Cropper also provides cross board experience.

        Bryan K. Guderian.    Mr. Guderian joined the board of directors of our general partner in May 2012. Mr. Guderian has served as Senior Vice President of Operations of WPX Energy, Inc. since August 2011. Mr. Guderian previously served as Vice President of the Exploration & Production unit of The Williams Companies, Inc. from 1998 until August 2011, where he had responsibility for overseeing international operations. Mr. Guderian has served as a director of Apco Oil & Gas International Inc., since 2002 and as a director of Petrolera Entre Lomas S.A. since 2003.

        Mr. Guderian brings considerable upstream experience to the board including executive, operational and financial expertise from 30 years of petroleum industry involvement, the majority of which has been focused in exploration and production.

        James C. Kneale.    Mr. Kneale joined the board of directors of our general partner in May 2011. Mr. Kneale served as President and Chief Operating Officer of ONEOK, Inc., from January 2007, and ONEOK Partners, L.P., from May 2008, until his retirement in January 2010. After joining ONEOK in 1981, Mr. Kneale served in various other roles, including Chief Financial Officer from 1999 through 2006. Mr. Kneale also served as a director of ONEOK Partners, L.P. from 2006 until his retirement in January 2010. Mr. Kneale is a former CPA and has a B.B.A. in Accounting in 1973 from West Texas A&M in Canyon, Texas.

        Mr. Kneale brings extensive executive, financial and operational experience to the board. With nearly 30 years of experience in the natural liquids gas industry in numerous positions, Mr. Kneale provides valuable insight into our business and industry.

        John T. Raymond.    Mr. Raymond joined the board of directors of our general partner in August 2013. Mr. Raymond is the Founder and Majority Owner of The Energy & Minerals Group of which he has been a Managing Partner and the Chief Executive Officer since its September 2006 inception. Mr. Raymond has held executive leadership positions with various energy companies, including President and Chief Executive Officer of Plains Resources Inc. (the predecessor entity of Vulcan Energy Corporation), President and Chief Operating Officer of Plains Exploration and Production Company and was a Director of Plains All American Pipeline, LP.

        Mr. Raymond is also currently a director of American Energy Ohio Holdings, LLC, Ferus Inc., Ferus Natural Gas Fuels Inc., Iron Ore Holdings, Lighthouse Oil & Gas GP, LLC, MarkWest Utica

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EMG, LLC, Medallion Midstream, LLC, Plains All American GP LLC and Tallgrass MLP GP LLC. Mr. Raymond manages various private investments through personally held Lynx Holdings, LLC. Mr. Raymond received a B.S.M. from the A.B. Freeman School of Business at Tulane University with dual concentrations in finance and accounting and currently sits on the Board of the Business School Council.

        Patrick Wade.    Mr. Wade has served as a member of the High Sierra board since November 2008 and a member of the board of directors of our general partner since 2012. Mr. Wade has twenty years of experience in the energy sector. In 2002, Mr. Wade co-founded Tiger Midstream Investments, a natural gas midstream development and investment company that was involved primarily in the United States Rockies. From 2005 to 2007, Mr. Wade was a Managing Director at Bear Energy LP, responsible for investments in natural gas midstream infrastructure, as well as contracting for a diverse portfolio of natural gas storage capacity. In 2008, Mr. Wade joined The Energy & Minerals Group ("EMG"), as a Managing Director in the Houston office. EMG is the management company for a series of specialized private equity funds. EMG focuses on investing across various facets of the global natural resource industry including the upstream and midstream segments of the energy complex. EMG has approximately $13.3 billion of regulatory assets under management (RAUM) and approximately $6.1 billion in commitments have been allocated across the energy sector since inception. EMG is the managing partner of EMG NGL HC LLC. Mr. Wade's primary focus is making direct investments across the natural resources industry. In addition, Mr. Wade serves on the board of directors of Medallion Midstream, L.L.C. and Ferus Inc. Mr. Wade received his Bachelor's degree from the University of Oklahoma in 1991 and his M.B.A. from the Jesse H. Jones School of Management at Rice University in 1995.

        Mr. Wade brings extensive financial and industry experience to the board. With almost 20 years of experience in the energy sector, Mr. Wade provides valuable insight into our business.

Director Appointment Rights

        The Limited Liability Company Agreement of NGL Energy Holdings LLC grants certain parties the right to designate a specified number of persons to serve on the board of directors. EMG NGL HC LLC has the right to designate two persons to serve on the board of directors, and has designated John Raymond and Patrick Wade. The Coady Group (which consists of certain entities controlled by Shawn W. Coady and Todd M. Coady) and the IEP Parties (which consists of certain entities controlled by H. Michael Krimbill, Bradley K. Atkinson, and another investor who is not a member of management of the Partnership) each have the right to designate one person to serve on the board of directors. The Coady Group has designated Shawn W. Coady and the IEP Parties have designated H. Michael Krimbill.

Board Leadership Structure and Role in Risk Oversight

        The board of directors of our general partner believes that whether the offices of chairman of the board and chief executive officer are combined or separated should be decided by the board, from time to time, in its business judgment after considering relevant circumstances. The board of directors of our general partner currently does not have a chairman.

        The board of directors and its committees regularly review material operational, financial, compensation and compliance risks with senior management. In particular, the audit committee is responsible for risk oversight with respect to financial and compliance risks and risks relating to our audit and independent registered public accounting firm. Our compensation committee considers risk in connection with its design and evaluation of compensation programs for our senior management. Each committee regularly reports to the board of directors.

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Audit Committee

        The board of directors of our general partner has established an audit committee. The audit committee assists the board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to, among other things:

        The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary.

        Mr. Cropper, Mr. Guderian, and Mr. Kneale currently serve on the audit committee, and Mr. Kneale serves as the chairman. The board of directors of our general partner has determined that Mr. Kneale, an independent director, is as an "audit committee financial expert" as defined under SEC rules and that each member of the audit committee is financially literate. In compliance with the requirements of the NYSE, all of the members of the audit committee are independent directors, as defined in the applicable NYSE rules.

Compensation Committee

        The board of directors of our general partner has established a compensation committee. The compensation committee's responsibilities include the following, among others:

        Mr. Cropper, and Mr. Kneale currently serve on the compensation committee. Mr. Cropper serves as the chairman. The board of directors has determined that Mr. Cropper and Mr. Kneale are independent directors under applicable NYSE and Exchange Act rules. The NYSE does not require a listed publicly-traded limited partnership to have a compensation committee consisting entirely of independent directors.

Corporate Governance

        The board of directors of our general partner has adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers, or Code of Ethics, that applies to the chief executive officer, chief financial officer, chief accounting officer, controller and all other senior financial and accounting officers of our general partner. Amendments to or waivers from the Code of Ethics will be disclosed on our website. The board of directors of our general partner has also adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of Business Conduct and Ethics that applies to the directors, officers and employees of our general partner and the Partnership.

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        We make available free of charge, within the "Governance" section of our website at http://www.nglenergypartners.com/governance, and in print to any unitholder who so requests, the Code of Ethics, the Corporate Governance Guidelines, the Code of Business Conduct and Ethics and the charters of the audit committee and the compensation committee of the board of directors of our general partner. Requests for print copies may be directed to Investor Relations at investorinfo@nglep.com or to Investor Relations, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, OK 74136 or made by telephone at (918) 481-1119. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.

Meeting of Non-Management Directors and Communications with Directors

        At each quarterly meeting of the audit committee and/or the board of directors of our general partner, our independent directors meet in an executive session without participation by management or non-independent directors. Mr. Kneale presides over these executive sessions.

        Unitholders or interested parties may communicate directly with the board of directors of our general partner, any committee of the board, any independent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of our Secretary at the following address: Name of the Director(s), c/o Secretary, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, OK 74136. Communications are distributed to the board, committee, or director as appropriate, depending on the facts and circumstances outlined in the communication.


EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

        The year "2014" in the Compensation Discussion and Analysis and the summary compensation table refers to our fiscal year ended March 31, 2014.

Introduction

        The board of directors of our general partner has responsibility and authority for compensation-related decisions for our executive officers. In November 2011, the board of directors formed a compensation committee to develop our compensation program, to determine the compensation of our Chief Executive Officer, and to make recommendations to the board of directors regarding the compensation of our other executive officers. Our executive officers are also officers of our operating companies and are compensated directly by our operating companies. While we reimburse our general partner and its affiliates for all expenses they incur on our behalf, our executive officers do not receive any additional compensation for the services they provide to our general partner.

        Our "named executive officers" for fiscal 2014 were:

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Compensation Philosophy

        Our compensation philosophy emphasizes pay-for-performance, focused primarily on the ability to increase sustainable quarterly distributions to our unitholders. Pay-for-performance is based on a combination of our performance and the individual executive officer's contribution to our performance. We believe this pay-for-performance approach generally aligns the interests of our executive officers with the interests of our unitholders, and at the same time enables us to maintain a lower level of cash compensation expense in the event our operating and financial performance do not meet our expectations.

        Our executive compensation program is designed to provide a total compensation package that allows us to:

Factors Enhancing Alignment with Unitholder Interests

Compensation Setting Process

        Our compensation program for our named executive officers supports our philosophy of pay-for-performance.

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        The compensation committee continues to monitor the independence of its compensation consultant on a periodic basis. The compensation committee is considering the recommendations provided by PM&P and is in the process of designing the fiscal 2015 compensation program.

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Elements of Executive Compensation

        As part of our pay-for-performance approach to executive compensation, the compensation of our executive officers includes a significant component of incentive compensation based on our performance. We use three primary elements of compensation in our executive compensation program:

 
   
   
  Objective Supported  
Element
  Primary
Purpose
  How
Amount
Determined
  Attract &
Retain
  Motivate &
Pay for
Performance
  Unitholder
Alignment
 
Base Salary  

Fixed income to compensate executive officers for their level of responsibility, expertise and experience

 

Based on competition in the marketplace for executive talent and abilities

    X              

Cash Bonus Awards

 

Rewards achievement of specific annual financial and operational performance goals

 

Based on the named executive officer's relative contribution to achieving or exceeding annual goals

   
X
   
X
   
X
 

 

Recognizes individual contributions to our performance

                       

Long-Term Equity Incentive Awards

 

Motivates and rewards the achievement of long-term performance goals, including increasing the market price of our common units and the quarterly distributions to our unitholders

 

Based on the named executive officer's expected contribution to long-term performance goals

   
X
   
X
   
X
 

 

Provides a forfeitable long-term incentive to encourage executive retention

                       

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Base Salary

        The compensation committee periodically reviews the base salaries of our named executive officers and may recommend adjustments as necessary. We do not make automatic annual adjustments to base salary.

Cash Bonus Awards

        Neither the compensation committee nor the Board of Directors has yet approved bonuses to be paid to the named executive officers based on performance during fiscal 2014. For fiscal 2014, none of the named executive officers was subject to a formal bonus plan, and therefore annual bonus awards for fiscal 2014 performance, if any, would be discretionary.

        During fiscal 2014, bonuses were paid to the named executive officers. These bonuses were approved by the Board of Directors in fiscal 2014 at the recommendation of the compensation committee, which determined the bonus amounts using recommendations provided by the Chief Executive Officer. The bonus amounts were determined based on the contributions of the individuals since the time they joined the Partnership through the date of the bonus and based on expectations of future performance. The amounts of these bonuses were as follows:

Atanas H. Atanasov

    195,000  

James J. Burke

    450,000  

Shawn W. Coady

    200,000  

David C. Kehoe

    425,000  

        Also during fiscal 2014, the compensation committee approved a bonus of $475,000 to be paid to H. Michael Krimbill. The bonus amount was determined based on the contributions of Mr. Krimbill since the time the Partnership was formed through the date of the bonus and based on expectations of future performance.

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        The cash bonus program for fiscal 2015 is still under development, as further described in the "Fiscal 2015 Compensation Program" section below.

Long-Term Equity Incentive Awards

        In May 2011, our general partner adopted the NGL Energy Partners LP 2011 Long-Term Incentive Plan (the "LTIP") for the employees and directors of our general partner who perform services for us. The LTIP authorizes the grant of restricted units, phantom units, unit options, unit appreciation rights and other unit-based awards.

        On June 27 2013, Mr. Atanasov was granted 10,000 restricted units in recognition of his increased responsibilities. The restricted units will vest in five equal annual installments, the first of which vests on July 1, 2014, subject to the continued service of Mr. Atanasov. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

        Previously, the compensation committee granted awards of restricted units to certain of our named executive officers during fiscal year 2013. Initial grants under the LTIP were awarded in June 2012 upon formation of the award program. Additional grants were awarded in December 2012, primarily for officers and employees who joined the Partnership in the merger with High Sierra. The fiscal year 2013 awards were designed to incentivize retention and to enhance unitholder alignment by rewarding the officer if the value of common units increases over time. These awards vest in tranches, subject to the continued service of the recipient. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

        The long-term equity incentive award program for fiscal 2015 is still under development, as further described in the "Competitive Review and Fiscal 2015 Compensation Program" section below.

Severance and Change in Control Benefits

        We do not provide any severance or change of control benefits to our named executive officers. The board of directors has the option to accelerate the vesting of the restricted units in the event of a change in control of the Partnership, although it is not under any obligation to do so.

401(k) Plan

        We have established a defined contribution 401(k) plan to assist our eligible employees in saving for retirement on a tax-deferred basis. The 401(k) plan permits all eligible employees, including our named executive officers, to make voluntary pre-tax contributions to the plan, subject to applicable tax limitations. We make an employer matching contribution equal to 50% of the employee's contribution that is not in excess of 6% of the employee's eligible compensation (subject to annual IRS contribution limits). Our matching contributions vest over 5 years.

Other Benefits

        We do not maintain a defined benefit or pension plan for our executive officers, because we believe such plans primarily reward longevity rather than performance. We provide a basic benefits package available to substantially all full-time employees, which includes a 401(k) plan and medical, dental, disability and life insurance.

Competitive Review and Fiscal 2015 Compensation Program

        During fiscal 2014, PM&P conducted a competitive review of our executive compensation program and provided input to the compensation committee regarding competitive compensation levels and

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compensation program design. In order to provide guidance to the compensation committee regarding competitive rates of compensation, PM&P collected pay data from the following sources:


Compensation Peer Group Companies

AmeriGas Partners LP   Enbridge Energy Partners, L.P.   Crosstex Energy LP
Ferrellgas Partners LP   NuStar Energy L.P.   DCP Midstream Partners LP
Star Gas Partners, L.P.   Targa Resources Partners LP   Martin Midstream Partners LP
Suburban Propane Partners, L.P.   Buckeye Partners, L.P.   Regency Energy Partners LP
ONEOK Partners, L.P.   Genesis Energy LP   Boardwalk Pipeline Partners, LP
Kinder Morgan Energy Partners, L.P.   Crestwood Midstream Partners LP   Western Gas Partners LP
Williams Partners L.P.   Magellan Midstream Partners LP    

        PM&P defines "market" as the combination of survey data and peer group data. The compensation committee is considering the recommendations provided by PM&P and is in the process of designing the fiscal 2015 compensation program.

Employment Agreements

        We do not have employment agreements with any of our named executive officers.

Deductibility of Compensation

        We believe that the compensation paid to the named executive officers is generally fully deductible for federal income tax purposes. We are a limited partnership and we do not meet the definition of a "corporation" subject to deduction limitations under Section 162(m) of the Code. Nonetheless, the taxable compensation paid to each of our named executive officers in calendar 2013 was less than the Section 162(m) threshold of $1,000,000. Although the value of the restricted units granted during fiscal 2014 are reflected in the Summary Compensation Table below, the grant is subject to vesting conditions. The vesting of the award is a taxable event, but the granting of the award is not.

Relation of Compensation Policies and Practices to Risk Management

        Our compensation arrangements contain a number of design elements that serve to minimize the incentive for taking excessive or inappropriate risk to achieve short-term, unsustainable results. This includes using restricted unit grants as a significant element of the executive compensation, as the restricted units are designed to reward the executives based on the long-term performance of the Partnership. In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.

Compensation Committee Interlocks and Insider Participation

        Dr. Coady is a member of the board of directors and an executive officer of our general partner, and his brother, Mr. Coady, is an executive officer of our general partner. Dr. Coady and Mr. Coady also serve as officers and directors of HOH, a family owned company. Both Dr. Coady and Mr. Coady participate in the compensation setting process of the HOH board of directors.

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Summary Compensation Table for 2014

        The following table includes the compensation earned by our named executive officers for fiscal years 2012-2014.

Name and Position
  Fiscal
Year
  Salary
($)
  Bonus
(1)
($)
  Restricted
Unit
Awards
(2)
($)
  All
Other
Compensation
(3)
($)
  Total
($)
 
H. Michael Krimbill     2014     117,693     475,000         6,493     599,186  

Chief Executive Officer

    2013     82,849             2,492     85,341  
      2012     110,769             2,700     113,469  

Atanas H. Atanasov(4)

 

 

2014

 

 

232,500

 

 

195,000

 

 

259,696

 

 

7,038

 

 

694,234

 

Chief Financial Officer

    2013     195,000         743,440     2,738     941,178  

James J. Burke(5)

 

 

2014

 

 

367,385

 

 

450,000

 

 


 

 

24,651

 

 

842,036

 

President

    2013     275,630         836,400     13,015     1,125,045  

Shawn W. Coady

 

 

2014

 

 

300,000

 

 

200,000

 

 


 

 

19,630

 

 

519,630

 

President and Chief Operating Officer, Retail Division

    2013     238,462         613,700     17,730     869,892  
      2012     285,587             20,950     306,537  

David C. Kehoe(5)

 

 

2014

 

 

323,731

 

 

425,000

 

 


 

 

15,932

 

 

764,663

 

Executive Vice President, NGL Crude Logistics

    2013     228,781         836,400     13,490     1,078,671  

(1)
Amounts for fiscal 2014 include discretionary bonuses paid in 2014 based on contributions of the individuals since the time they joined the Partnership through the date of the bonus and based on expectations of future performance. Amounts payable based on fiscal 2014 performance, if any, have not yet been determined, but are expected to be determined during the first or second quarters of fiscal 2015.

(2)
The fair values of the restricted units shown in the table above were calculated based on the closing market prices of our limited partner units on the grant dates, with adjustments made to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution prior to the grant date and assumptions that a market participant might make about future distribution growth. This calculation of fair value is consistent with the provisions of ASC 718.

(3)
The amounts in this column include matching contributions to our 401(k) plan. Amounts for Mr. Burke and Mr. Kehoe each include $8,124 for club memberships. The fiscal 2014 amount for Mr. Burke includes $9,000 for a car allowance. Amounts in this column for Dr. Coady include matching contributions to our 401(k) plan of $8,750 for fiscal 2014. Amounts in this column for Dr. Coady also include the incremental cost of the use of a company car, including depreciation, maintenance, insurance, and fuel, of $10,880 for fiscal 2014.

(4)
Mr. Atanasov was not a named executive officer prior to fiscal 2013.

(5)
Mr. Burke and Mr. Kehoe joined our management team upon completion of our merger with High Sierra on June 19, 2012.

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Restricted Unit Awards

        During fiscal 2014, the board of directors granted an award of restricted units to Mr. Atanasov. The restricted units will vest in tranches, subject to his continued service. The restricted units may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

2014 Grants of Plan Based Awards Table

        The number of restricted units granted to our named executive officers, and their grant date fair value, are summarized below:

Name
  Grant
Date
  Total Number of
Restricted Units
Awarded
  Grant Date Fair Value
of Restricted Units
Awarded
($)
 

H. Michael Krimbill

  n/a          

Atanas H. Atanasov

  June 27, 2013     10,000     259,696  

James J. Burke

  n/a          

Shawn W. Coady

  n/a          

David C. Kehoe

  n/a          

        The fair value of the restricted units shown in the table above were calculated based on the closing market price of our limited partner units on the grant date, with adjustments made to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution at the grant date and assumptions that a market participant might make about future distribution growth.

        We record in our consolidated financial statements the expense for each tranche on a straight-line basis over the period beginning with the vesting of the previous tranche and ending with the vesting of the tranche. We adjust the cumulative expense recorded through each reporting date using the estimated fair value of the awards at the reporting date.

Outstanding Equity Awards as of March 31, 2014

        The number of unvested restricted units outstanding at March 31, 2014, and their fair values at March 31, 2014, are summarized below:

Name
  Number of Restricted Units
That Have Not Yet Vested
at March 31, 2014
  Fair Value of Unvested
Restricted Units
as of March 31, 2014
($)
 

H. Michael Krimbill

         

Atanas H. Atanasov

    32,000     1,200,960  

James J. Burke

    40,000     1,501,200  

Shawn W. Coady

    10,000     375,300  

David C. Kehoe

    40,000     1,501,200  

        The fair values of the restricted units shown in the table above were calculated based on the closing market price of our limited partner units at March 31, 2014 of $37.53. No adjustments were made to reflect the fact that the restricted units are not entitled to distributions during the vesting period.

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2014 Option Exercises and Stock Vested

        On July 1, 2013, certain of the restricted units granted vested. The value of the awards on the vesting date shown in the table below was calculated based of the closing market price of $30.49 per unit on the vesting date.

Name
  Number of Units Acquired
on Vesting
  Value Realized on Vesting
($)
 

H. Michael Krimbill

         

Atanas H. Atanasov

    10,000     304,900  

James J. Burke

    10,000     304,900  

Shawn W. Coady

    10,000     304,900  

David C. Kehoe

    10,000     304,900  

        Upon vesting, certain of the named executive officers elected for us to remit payments to taxing authorities in lieu of issuing units. Mr. Atanasov elected to have 3,260 units withheld, Mr. Burke elected to have 3,181 units withheld, Dr. Coady elected to have 4,235 units withheld, and Mr. Kehoe elected to have 3,184 units withheld for this purpose.

        Subsequent to vesting, these individuals received distributions of $1.54 on each of the vested units during the fiscal year ended March 31, 2014.

Potential Payments upon Termination or Change in Control

        We do not provide any severance or change of control benefits to our executive officers. The board of directors has the option to accelerate the vesting of the restricted units in the event of a change in control of the Partnership, although it is not under any obligation to do so. If the board of directors were to exercise its discretion to accelerate the vesting of restricted units upon a change in control, the value of such units would be the same as reported in the "Outstanding Equity Awards as of March 31, 2014" table above.

Director Compensation

        Officers or employees of our general partner and its affiliates who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director who is not an officer or employee of our general partner or its affiliates receives the following compensation for his board service:

        All of our directors are also reimbursed for all out-of-pocket expenses incurred in connection with attending board or committee meetings. Each director is indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

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Director Compensation for Fiscal 2014

        The following table sets forth the compensation earned during fiscal 2014 by each director who is not an officer or employee of our general partner:

Name
  Fees Earned or
Paid in Cash
($)
  Restricted Unit
Awards
($)
  Total
($)
 

Stephen L. Cropper

    65,000         65,000  

Bryan K. Guderian

    65,000         65,000  

James C. Kneale

    70,000         70,000  

        These directors did not receive any equity grants under the LTIP during fiscal 2014. During fiscal 2013, each of these directors received a grant of unvested units under the LTIP. These units vest in tranches, contingent on the continued service of the directors. During fiscal 2014, a tranche of 5,000 units vested for each director. Subsequent to the vesting, these individuals received distributions of $1.54 on each of the vested units.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

Security Ownership of Certain Beneficial Owners and Management

        The following table sets forth the beneficial ownership, as of May 23, 2014 of our units by:

Beneficial Owners
  Common
Units
Beneficially
Owned
  Percentage of
Common Units
Beneficially
Owned(1)
  Subordinated
Units
Beneficially
Owned
  Percentage of
Subordinated
Units
Beneficially
Owned(1)
  Percentage of
Total Common
and
Subordinated
Units
Beneficially
Owned(1)
 

5% or greater unitholders (other than officers and directors):

                               

SemGroup Corporation(2)

    9,133,409     12.23 %           11.33 %

Oppenheimer Funds, Inc.(3)

    8,559,178     11.46 %           10.62 %

Goldman Sachs Asset Management, L.P.(4)

    4,938,229     6.61 %           6.12 %

Directors and officers:

   
 
   
 
   
 
   
 
   
 
 

Atanas H. Atanasov(5)

    43,908     *             *  

James J. Burke(6)

    308,259     *             *  

Kevin C. Clement

    5,000     *             *  

Shawn W. Coady(7)

    1,326,370     1.78 %   1,125,351     19.01 %   3.04 %

Carlin G. Conner

                     

Stephen L. Cropper

    25,000     *             *  

Bryan K. Guderian

    20,000     *             *  

David C. Kehoe(8)

    315,823     *             *  

James C. Kneale(9)

    17,500     *             *  

H. Michael Krimbill(10)

    970,557     1.30 %   497,846     8.41 %   1.82 %

Vincent J. Osterman(11)

    3,955,437     5.29 %           4.94 %

Patrick Wade

                     

John T. Raymond(12)

    2,176,634     2.91 %           2.70 %

All directors and executive officers as a group (15 persons)(13)

    10,491,438     14.04 %   2,747,198     46.41 %   16.45 %

*
Less than 1.0%

(1)
Based on 74,706,160 common units and 5,919,346 subordinated units outstanding at May 23, 2014.

(2)
The mailing address for SemGroup Corporation is 6120 S. Yale Avenue, Suite 700, Tulsa, OK 74136. SemGroup Corporation also owns an 11.78% interest in our general partner. The information related to SemGroup Corporation, including the number of common units held, is based upon its Form 4 filed with the SEC on June 10, 2013.

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        Unless otherwise noted, each of the individuals listed above is believed to have sole voting and investment power with respect to the units beneficially held by them. The mailing address for each of the officers and directors of our general partner listed above is 6120 South Yale Avenue, Suite 805, Tulsa, OK 74136.

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DESCRIPTION OF NOTES

        You can find the definitions of certain terms used in this description under the subheading "—Definitions." In this description, the words "NGL Energy," "us," "our" and "we" refer only to NGL Energy Partners LP and not to any of its Subsidiaries, and the words "Finance Corp." refer solely to NGL Energy Finance Corp. The term "Issuers" refers to NGL Energy and Finance Corp., collectively.

        The Issuers will issue new notes under an indenture dated as of October 16, 2013 (the "indenture"), among the Issuers, the Guarantors and U.S. Bank National Association, as trustee (the "trustee"), in exchange for old notes issued under the indenture in a private transaction that was not subject to the registration requirements of the Securities Act. See "Notice to Investors." The terms of the notes will include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended (the "Trust Indenture Act").

        The following description is a summary of the material provisions of the indenture. It does not restate the indenture in its entirety. We urge you to read the indenture because it, and not this description, defines your rights as holders of the notes. The registered holder of a note will be treated as the owner of it for all purposes. Only registered holders will have rights under the indenture and all references to "holders" in this description are to registered holders of notes.

        The new notes will:

        Initially, the new notes will be guaranteed by each Restricted Subsidiary (other than Finance Corp.) that is a Domestic Subsidiary and an obligor under the Credit Agreement. In the future, other Restricted Subsidiaries will be required to guarantee the notes under the circumstances described below under "—Covenants—Additional Note Guarantees." Each guarantee of the notes will:

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        As of the Issue Date, all of our Restricted Subsidiaries will guarantee the notes, other than NGL Gateway Terminals, Inc., High Sierra Energy GP, LLC, High Sierra Energy Shared Services, LLC, High Sierra Storage, LLC, Petro Source Products, LLC, High Sierra Energy Canada ULC, High Sierra Water Services Midcontinent, LLC and Indigo Injection #3-1, LLC. As of the Issue Date, none of these Subsidiaries Guarantees (or is otherwise liable for) any Obligations under any Credit Facility, including the Credit Agreement. As of the Issue Date, all of our Subsidiaries will be "Restricted Subsidiaries." However, under the circumstances described below under the caption "—Covenants—Designation of Restricted and Unrestricted Subsidiaries," we will be permitted to designate certain of our Subsidiaries as "Unrestricted Subsidiaries." Our Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the indenture. In the event of a bankruptcy, liquidation or reorganization of any Unrestricted Subsidiary, such Unrestricted Subsidiary will pay the holders of its debt and its trade creditors before it will be able to distribute any of its assets to NGL Energy.

        The Issuers will issue up to $450.0 million in aggregate principal amount of new notes in this exchange offer. The Issuers may issue additional notes under the indenture from time to time after this offering. Any issuance of additional notes is subject to all of the covenants in the indenture, including the covenant described below under the caption "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock." The notes and any additional notes subsequently issued under the indenture will be treated as a single class for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase. The Issuers will issue notes in denominations of $2,000 and integral multiples of $1,000 in excess of $2,000. The notes will mature on October 15, 2021.

        Interest on the notes will accrue at the rate of 6.875% per annum and will be payable semi-annually in arrears on April 15 and October 15 of each year. The Issuers will make each interest payment to the holders of record on the immediately preceding April 1 and October 1.

        Interest on the notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months. If an interest payment date falls on a day that is not a Business Day, the interest payment to be made on such interest payment date will be made on the next succeeding Business Day with the same force and effect as if made on such interest payment date, and no Liquidated Damages will accrue as a result of such delayed payment.

        If a holder of notes has given wire transfer instructions to NGL Energy, NGL Energy will pay all principal, interest and premium, if any, on that holder's notes in accordance with those instructions to an account in the United States of America. All other payments on the notes will be made at the office or agency of the paying agent and registrar in New York, New York, unless we elect to make interest payments by check mailed to the noteholders at their address set forth in the register of holders.

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        The trustee is acting as paying agent and registrar. The Issuers may change the paying agent or registrar without prior notice to the holders of the notes, and NGL Energy or any of its Subsidiaries may act as paying agent or registrar.

        A holder may transfer or exchange notes in accordance with the provisions of the indenture. The registrar and the trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. Holders will be required to pay all taxes due on transfer. The Issuers will not be required to transfer or exchange any note selected for redemption. Also, the Issuers will not be required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed or between a record date and the next succeeding interest payment date.

        Initially, all of the notes will be guaranteed on a senior unsecured basis by each of NGL Energy's current Restricted Subsidiaries (except Finance Corp.) that is a Domestic Subsidiary and an obligor under the Credit Agreement. In the future, Restricted Subsidiaries will be required to guarantee the notes under the circumstances described under "—Covenants—Additional Note Guarantees." These Note Guarantees will be joint and several obligations of the Guarantors. The obligations of each Guarantor under its Note Guarantee will be limited as necessary to prevent that Note Guarantee from constituting a fraudulent conveyance under applicable law, although this limitation may not be effective to prevent the Note Guarantees from being voided in bankruptcy. See "Risk Factors—Risks Related to the Notes—Federal and state statutes allow courts, under specific circumstances, to void guarantees and require noteholders to return payments received from subsidiary guarantors."

        A Guarantor may not sell or otherwise dispose of, in one or more related transactions, all or substantially all of its properties or assets to, or consolidate with or merge with or into (regardless of whether such Guarantor is the surviving Person), another Person, other than NGL Energy or another Guarantor, unless:

        The Note Guarantee of a Guarantor will be released automatically:

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        Except as described below in this section or in the next-to-last paragraph of "—Repurchase at the Option of Holders—Change of Control," the notes are not redeemable at our option until October 15, 2016. On and after October 15, 2016, NGL Energy may redeem all or a part of the notes, from time to time, at the following redemption prices (expressed as a percentage of the principal amount) plus accrued and unpaid interest, if any, on the notes redeemed to the applicable redemption date (subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the twelve month period beginning on of the years indicated below:

Year
  Redemption
Price
 

2016

    105.156 %

2017

    103.438 %

2018

    101.719 %

2019 and thereafter

    100.000 %

        At any time or from time to time prior to 2016, NGL Energy may also redeem all or a part of the notes, at a redemption price equal to the Make-Whole Price, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date.

        "Make-Whole Price" with respect to any notes to be redeemed, means an amount equal to the greater of:

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plus, in the case of both (1) and (2), accrued and unpaid interest on such notes, if any, to the redemption date.

        "Comparable Treasury Issue" means, with respect to notes to be redeemed, the U.S. Treasury security selected by an Independent Investment Banker as having a maturity most nearly equal to the period from the redemption date to October 15, 2016, that would be utilized at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of a comparable maturity; provided that if such period is less than one year, then the U.S. Treasury security having a maturity of one year shall be used.

        "Comparable Treasury Price" means, with respect to any redemption date, (1) the average of the Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest of such Reference Treasury Dealer Quotations, or (2) if the trustee obtains fewer than five such Reference Treasury Dealer Quotations, the average of all such Reference Treasury Dealer Quotations.

        "Independent Investment Banker" means RBC Capital Markets, LLC, RBS Securities Inc. and Deutsche Bank Securities Inc., or one of their respective successors, or, if such firms or their respective successors, if any, as the case may be, are unwilling or unable to select the Comparable Treasury Issue, an independent investment banking institution of national standing appointed by NGL Energy.

        "Primary Treasury Dealer" means a U.S. government securities dealer in the City of New York.

        "Reference Treasury Dealer" means each of RBC Capital Markets, LLC, RBS Securities Inc. and Deutsche Bank Securities Inc. and two additional Primary Treasury Dealers selected by NGL Energy, and their respective successors; provided, however, that if any such firm or any such successor, as the case may be, shall cease to be a Primary Treasury Dealer, NGL Energy shall substitute therefor another Primary Treasury Dealer.

        "Reference Treasury Dealer Quotations" means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the trustee by such Reference Treasury Dealer at 5:00 p.m., New York City time, no later than the fourth Business Day preceding such redemption date.

        "Treasury Rate" means, with respect to any redemption date, (1) the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated "H.15(159)" or any successor publication that is published weekly by the Board of Governors of the Federal Reserve System and that establishes yields on actively traded U.S. Treasury securities adjusted to constant maturity under the caption "Treasury Constant Maturities," for the maturity corresponding to the Comparable Treasury Issue (if no maturity is within three months before or after the stated maturity, yields for the two published maturities most closely corresponding to the Comparable Treasury Issue shall be determined, and the Treasury Rate shall be interpolated or extrapolated from such yields on a straight-line basis, rounding to the nearest month) or (2) if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per annum equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, calculated using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date. The Treasury Rate shall be calculated no later than the fourth Business Day preceding the redemption date.

        The notice of redemption with respect to the foregoing redemption need not set forth the Make-Whole Price but only the manner of calculation thereof. NGL Energy will notify the trustee of

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the Make-Whole Price with respect to any redemption promptly after the calculation, and the trustee shall not be responsible for such calculation.

        Prior to October 15, 2016, NGL Energy may on any one or more occasions redeem up to 35% of the principal amount of the notes with an amount of cash not greater than the amount of the net cash proceeds from one or more Equity Offerings at a redemption price equal to 106.875% of the principal amount thereof, plus accrued and unpaid interest, if any, on the notes redeemed to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date); provided that

        If less than all of the notes are to be redeemed at any time, the trustee will select notes for redemption on a pro rata basis (or, in the case of notes in global form, the trustee will select notes for redemption based on the method of The Depository Trust Company ("DTC") that most nearly approximates a pro rata selection), unless otherwise required by law or applicable stock exchange requirements.

        No notes of $2,000 or less can be redeemed in part. Notices of optional redemption will be mailed by first class mail (or, in the case of notes in global form, pursuant to the applicable procedures of DTC) at least 30 but not more than 60 days before the redemption date to each holder of notes to be redeemed at its registered address, except that redemption notices may be sent more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the indenture.

        If any note is to be redeemed in part only, the notice of redemption that relates to such note shall state the portion of the principal amount thereof to be redeemed. A new note in principal amount equal to the unredeemed portion thereof will be issued in the name of the holder thereof upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption, unless the redemption is subject to a condition precedent that is not satisfied or waived. On and after the redemption date, interest ceases to accrue on notes or portions of notes called for redemption, unless NGL Energy defaults in making the redemption payment. Any redemption or notice of redemption may, at our discretion, be subject to one or more conditions precedent and, in the case of a redemption with the net cash proceeds of an Equity Offering, be given prior to and conditioned on the completion of the related Equity Offering.

        We may at any time and from time to time purchase notes in the open market or otherwise. The Issuers are not required to make mandatory redemption or sinking fund payments with respect to the notes.

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        If a Change of Control occurs, each holder of notes will have the right, except as provided below, to require NGL Energy to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of that holder's notes pursuant to an offer ("Change of Control Offer") on the terms set forth in the indenture. In the Change of Control Offer, NGL Energy will offer to make a cash payment (a "Change of Control Payment") equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest on the notes repurchased to the date of purchase (the "Change of Control Purchase Date"), subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date. Within 30 days following any Change of Control, NGL Energy will send a notice to each holder of notes describing the transaction or transactions that constitute the Change of Control and offering to repurchase properly tendered notes on the Change of Control Purchase Date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is sent, pursuant to the procedures required by the indenture and described in such notice. NGL Energy will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes of any series as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the indenture, NGL Energy will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the indenture by virtue of such compliance.

        Promptly following the expiration of the Change of Control Offer, NGL Energy will, to the extent lawful, accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer. Promptly after such acceptance, NGL Energy will, on the Change of Control Purchase Date:

        The paying agent will promptly mail or wire transfer to each holder of notes properly tendered the Change of Control Payment for such notes (or, if all the notes are then in global form, make such payment through the facilities of DTC), and the trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any; provided that each such new note will be in a principal amount of $2,000 or an integral multiple of $1,000 in excess of $2,000. Any note so accepted for payment will cease to accrue interest on and after the Change of Control Purchase Date, unless NGL Energy defaults in making the Change of Control Payment. NGL Energy will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Purchase Date.

        The provisions described above that require NGL Energy to make a Change of Control Offer following a Change of Control will be applicable regardless of whether any other provisions of the indenture are applicable, except as described in the following paragraph. Except as described above with respect to a Change of Control, the indenture does not contain provisions that permit the holders of the notes to require that the Issuers repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

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        NGL Energy will not be required to make a Change of Control Offer upon a Change of Control, if (1) a third party makes the Change of Control Offer in the manner, at the time and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by NGL Energy and purchases all notes properly tendered and not withdrawn under the Change of Control Offer, (2) notice of redemption of all outstanding notes has been given pursuant to the indenture as described above under the caption "—Optional Redemption—Selection and Notice," unless and until there is a default in payment of the applicable redemption price, or (3) in connection with or in contemplation of any Change of Control, NGL Energy has made an offer to purchase (an "Alternate Offer") any and all notes validly tendered at a cash price equal to or higher than the Change of Control Payment and has purchased all notes properly tendered in accordance with the terms of the Alternate Offer. Notwithstanding anything to the contrary contained in the indenture, a Change of Control Offer or Alternate Offer may be made in advance of a Change of Control, conditioned upon the consummation of such Change of Control, if a definitive agreement is in place for the Change of Control at the time the Change of Control Offer or Alternate Offer is made.

        In the event that holders of not less than 90% in aggregate principal amount of the outstanding notes accept a Change of Control Offer or Alternate Offer and NGL Energy (or any third party making such Change of Control Offer in lieu of NGL Energy as described above) purchases all of the notes held by such holders, NGL Energy will have the right, upon not less than 30 nor more than 60 days' prior notice, given not more than 30 days following the purchase pursuant to the Change of Control Offer or Alternate Offer described above, to redeem all of the notes that remain outstanding following such purchase at a redemption price equal to the Change of Control Payment plus, to the extent not included in the Change of Control Payment, accrued and unpaid interest on the notes that remain outstanding, to the date of redemption (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date).

        The definition of Change of Control includes a phrase relating to the sale, lease, transfer, conveyance or other disposition of "all or substantially all" of the properties or assets of NGL Energy and its Restricted Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require the Issuers to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of NGL Energy and its Restricted Subsidiaries taken as a whole to another Person or group may be uncertain.

        NGL Energy will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:

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        Within 365 days after the receipt of any Net Proceeds from an Asset Sale or, if NGL Energy has entered into a binding commitment or commitments with respect to any of the actions described in clauses (2) or (3) below, within the later of (x) 365 days after the receipt of any Net Proceeds from an Asset Sale and (y) 120 days after the entering into of such commitment or commitments, NGL Energy or one or more of its Restricted Subsidiaries may apply an amount equal to the amount of such Net Proceeds:

        Pending the final application of any Net Proceeds, NGL Energy or any of its Restricted Subsidiaries may temporarily reduce revolving credit borrowings or otherwise invest the Net Proceeds in any manner that is not prohibited by the indenture. An amount equal to any Net Proceeds from Asset Sales that are not applied or invested as provided in in clauses (1) through (3) of the immediately preceding paragraph will constitute "Excess Proceeds." Within ten Business Days after the aggregate amount of Excess Proceeds exceeds $30.0 million, the Issuers will make an offer (an "Asset Sale Offer") to all holders of notes and all holders of other Indebtedness that is pari passu with the notes containing provisions similar to those set forth in the indenture with respect to offers to purchase, prepay or redeem with the proceeds of sales of assets to purchase, prepay or redeem the maximum principal amount of notes and such other pari passu Indebtedness (plus all accrued interest on the Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith) that may be purchased, prepaid or redeemed out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of the principal amount, plus accrued and unpaid interest, if any, to the date of purchase, prepayment or redemption, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, NGL Energy or any Restricted Subsidiary may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes and other pari passu Indebtedness tendered in (or required to be prepaid or redeemed in connection with) such Asset Sale Offer exceeds the amount of Excess Proceeds, the trustee will select the notes and such other pari passu Indebtedness to be purchased on a pro rata basis (except that any notes represented by a note in global form will be selected by such method as DTC or its nominee or successor may require or, where such nominee or successor is the trustee, a method that most nearly approximates pro rata selection as

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the trustee deems fair and appropriate unless otherwise required by law), based on the amounts tendered or required to be prepaid or redeemed (with such adjustments as may be deemed appropriate by NGL Energy so that only notes in denominations of $2,000, or an integral multiple of $1,000 in excess thereof, will be purchased). Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero.

        Notwithstanding the foregoing, the sale, conveyance or other disposition of all or substantially all of the properties or assets of NGL Energy and its Restricted Subsidiaries, taken as a whole, will be governed by the provisions of the indenture described under the caption "—Repurchase at the Option of Holders—Change of Control" and/or the provisions described under the caption "—Covenants—Merger, Consolidation or Sale of Substantially All Assets" and not by the provisions of the indenture described under the caption "—Repurchase at the Option of Holders—Asset Sales."

        NGL Energy will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sales provisions of the indenture, or compliance with the Asset Sale provisions of the indenture would constitute a violation of any such laws or regulations, NGL Energy will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the indenture by virtue of such compliance. The agreements governing NGL Energy's other Indebtedness contain, and future agreements may contain, prohibitions of certain events, including events that would constitute a Change of Control or an Asset Sale and including repurchases of or other prepayments in respect of the notes. The exercise by the holders of notes of their right to require the Issuers to repurchase the notes upon a Change of Control or an Asset Sale could cause a default under these other agreements, even if the Change of Control or Asset Sale itself does not, due to the financial effect of such repurchases on NGL Energy. In the event a Change of Control or Asset Sale occurs at a time when NGL Energy is prohibited from purchasing notes, NGL Energy could seek the consent of its senior lenders to the purchase of notes or could attempt to refinance the borrowings that contain such prohibition. If NGL Energy does not obtain a consent or repay those borrowings, NGL Energy will remain prohibited from purchasing notes. In that case, NGL Energy's failure to purchase tendered notes would constitute an Event of Default under the indenture which could, in turn, constitute a default under the other indebtedness. Finally, the Issuers' ability to pay cash to the holders of notes upon a repurchase may be limited by NGL Energy's then-existing financial resources. See "Risk Factors—Risks Relating to the Notes—We may not be able to repurchase the notes upon a Change of Control."

        From and after the occurrence of an Investment Grade Rating Event, and provided that no Default or Event of Default shall have occurred and be continuing, we and our Restricted Subsidiaries will no longer be subject to the following provisions of the indenture (collectively, the "Terminated Covenants"):

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        Furthermore, after an Investment Grade Rating Event, NGL Energy may not designate any of its Subsidiaries as Unrestricted Subsidiaries.

        Consequently, after the date on which we and our Restricted Subsidiaries are no longer subject to the Terminated Covenants, the notes will be entitled to substantially reduced covenant protection. However, we and our Restricted Subsidiaries will remain subject to all other covenants in the indenture. There can be no assurance that the notes will ever achieve or maintain an Investment Grade Rating.

        NGL Energy will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

(all such payments and other actions set forth in clauses (1) through (4) above being collectively referred to as "Restricted Payments"), unless, at the time of and after giving effect to such Restricted Payment, no Default (except a Reporting Default) or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment and either:

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provided, however, that the only Restricted Payments permitted to be made pursuant to this clause (II) are distributions on NGL Energy's common and subordinated units plus the related distributions on the General Partner's general partner interest and any distributions with respect to incentive distribution rights.

        The preceding provisions will not prohibit:

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        The amount of all Restricted Payments (other than cash) will be the Fair Market Value, determined as of the date of the Restricted Payment, of the Restricted Investment proposed to be made or the asset(s) or securities proposed to be transferred or issued by NGL Energy or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment, except that the Fair Market Value of any non-cash dividend or distribution paid within 60 days after the date of its declaration shall be determined as of such date of declaration. The Fair Market Value of any

        Restricted Investment, assets or securities that are required to be valued by this covenant will be determined in accordance with the definition of that term. For purposes of determining compliance with this "Restricted Payments" covenant, (x) in the event that a Restricted Payment meets the criteria of more than one of the categories of Restricted Payments described in the preceding clauses (1) through (12) of this covenant, or is permitted pursuant to the first paragraph of this covenant, NGL Energy will be permitted to classify (or later classify or reclassify in whole or in part in its sole discretion) such Restricted Payment (or portion thereof) on the date made or later reclassify such Restricted Payment (or portion thereof) in any manner that complies with this covenant; and (y) in the event a Restricted Payment is made pursuant to clause (I) or (II) of the first paragraph of this covenant, NGL Energy will be permitted to classify whether all or any portion thereof is being (and in the absence of such classification shall be deemed to have classified the minimum amount possible as having been) made with Incremental Funds.

        NGL Energy will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, Guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, "incur"; with "incurrence" having a correlative meaning) any Indebtedness (including Acquired Debt), and NGL Energy will not issue any Disqualified Stock and will not permit any of its Restricted Subsidiaries to issue any shares of preferred stock; provided, however, that NGL Energy may incur Indebtedness (including Acquired Debt) and issue Disqualified Stock, and its Restricted Subsidiaries may incur Indebtedness (including Acquired Debt) and issue preferred stock, if the Fixed Charge Coverage Ratio for NGL Energy's most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the

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date on which such additional Indebtedness is incurred or such Disqualified Stock or such preferred stock is issued, as the case may be, would have been at least 2.0 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or the Disqualified Stock or the preferred stock had been issued, as the case may be, at the beginning of such four-quarter period.

        Notwithstanding the foregoing, the first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness or issuances of Disqualified Stock or preferred stock, as applicable (collectively, "Permitted Debt"):

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provided that, immediately after giving effect to any such incurrence, the principal amount of all Indebtedness incurred pursuant to this clause (12) and then outstanding does not exceed $25.0 million;

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        NGL Energy will not incur, and will not permit any Guarantor to incur, any Indebtedness (including Permitted Debt) that is contractually subordinated in right of payment to any other Indebtedness of NGL Energy or such Guarantor unless such Indebtedness is also contractually subordinated in right of payment to the notes or the applicable Note Guarantee on substantially identical terms; provided, however, that no Indebtedness will be deemed to be contractually subordinated in right of payment to any other Indebtedness of NGL Energy or any Guarantor solely by virtue of being unsecured or by virtue of being secured on a junior priority basis.

        For purposes of determining compliance with this "Incurrence of Indebtedness and Issuance of Preferred Stock" covenant, in the event that an item of Indebtedness (including Acquired Debt) meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (15) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, NGL Energy will be permitted in its sole discretion to divide, redivide, classify or reclassify such item of Indebtedness on the date of its incurrence, and later divide, redivide, classify or reclassify all or a portion of such item of Indebtedness, in any manner that complies with this covenant.

        Indebtedness under Credit Facilities outstanding on the date on which notes are first issued and authenticated under the indenture will initially be deemed to have been incurred on such date in reliance on the exception provided by clause (1) of the definition of Permitted Debt. The accrual of interest or preferred stock dividends, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, the reclassification of any obligation of NGL Energy or any Restricted Subsidiary as Indebtedness due to a change in accounting principles, and the payment of dividends on preferred stock or Disqualified Stock in the form of additional shares of the same class of preferred stock or Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of preferred stock or Disqualified Stock for purposes of this covenant; provided that, in each such case, the amount thereof is included in Fixed Charges of NGL Energy as accrued to the extent required by the definition of such term.

        For purposes of determining compliance with any U.S. dollar-denominated restriction on the incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency shall be utilized, calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was incurred, in the case of term Indebtedness, or first committed, in the case of revolving credit Indebtedness; provided that if such Indebtedness is incurred to refinance other Indebtedness denominated in a foreign currency, and such refinancing would cause the applicable U.S. dollar-denominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such refinancing, such U.S. dollar-denominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of such Indebtedness being refinanced. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that NGL Energy or any Restricted Subsidiary may incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in exchange rates or currency values. The principal amount of any Permitted Refinancing Indebtedness incurred to refinance other Indebtedness, if incurred in a different currency from the Indebtedness being refinanced, shall be calculated based on the currency exchange rate applicable to the currencies in which such Permitted Refinancing Indebtedness is denominated that is in effect on the date of such refinancing.

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        NGL Energy will not, and will not permit any of its Restricted Subsidiaries to, create, incur, assume or otherwise cause or suffer to exist or become effective any Lien of any kind (other than Permitted Liens) securing Indebtedness upon any of their property or assets, now owned or hereafter acquired, unless the notes or any Note Guarantee are secured on an equal and ratable basis with the Indebtedness so secured until such time as such Indebtedness is no longer secured by a Lien (other than a Permitted Lien).

        Any Lien securing the notes or Note Guarantees created pursuant to the preceding paragraph shall provide by its terms that such Lien shall be automatically and unconditionally released and discharged upon the unconditional release and discharge of the initial Lien whose existence resulted in the creation of such Lien securing the notes or Note Guarantees.

        NGL Energy will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:

        However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:

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        Neither of the Issuers may (1) consolidate or merge with or into another Person (regardless of whether such Issuer is the surviving entity), or (2) sell, assign, transfer, convey, lease or otherwise dispose of all or substantially all of its properties or assets, in one or more related transactions, to another Person, unless:

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        Notwithstanding the restrictions described in the foregoing clause (4), any Restricted Subsidiary (other than Finance Corp.) may consolidate with, merge into or dispose of all or part of its properties or assets to NGL Energy without complying with the preceding clause (4) in connection with any such consolidation, merger or disposition.

        Notwithstanding the second preceding paragraph, NGL Energy is permitted to reorganize as any other form of entity, provided that:

        For purposes of the foregoing, the transfer (by lease, assignment, sale or otherwise, in a single transaction or series of transactions) of all or substantially all of the properties or assets of one or more Restricted Subsidiaries, which properties or assets, if held by NGL Energy instead of such Restricted Subsidiaries, would constitute all or substantially all of the properties or assets of NGL Energy on a consolidated basis, shall be deemed to be the transfer of all or substantially all of the properties or assets of NGL Energy.

        Notwithstanding anything in the indenture to the contrary, in the event that NGL Energy becomes a corporation or NGL Energy or the Person formed by or surviving any consolidation or merger (permitted in accordance with the terms of the indenture) is a corporation, Finance Corp. may be merged into NGL Energy or it may be dissolved and cease to be an Issuer.

        Upon any consolidation or merger or any sale, assignment, transfer, conveyance, lease or other disposition of all or substantially all of the properties or assets of an Issuer in accordance with the foregoing in which such Issuer is not the surviving entity, the surviving Person formed by such consolidation or into or with which such Issuer is merged or to which such sale, assignment, transfer, conveyance, lease or other disposition is made shall succeed to, and be substituted for, and may exercise every right and power of, such Issuer under the indenture with the same effect as if such surviving Person had been named as such Issuer in the indenture, and thereafter (except in the case of a lease of all or substantially all of such Issuer's properties or assets), such Issuer will be relieved of all obligations and covenants under the indenture and the notes. Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to

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whether a particular transaction would involve "all or substantially all" of the properties or assets of a Person.

        NGL Energy will not, and will not permit any of its Restricted Subsidiaries to, make any payment to or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate of NGL Energy (each, an "Affiliate Transaction"), unless:

        The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:

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        Finance Corp. will not hold any material assets, become liable for any material obligations, engage in any trade or business, or conduct any business activity, other than the issuance of capital stock to NGL Energy, the incurrence of Indebtedness as a co-issuer, co-obligor or guarantor of Indebtedness incurred by NGL Energy including without limitation the notes) that is permitted to be incurred by NGL Energy under the covenant described under "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock" above, and activities incidental thereto.

        If, on any date after the Issue Date, any Domestic Subsidiary that is not already a Guarantor, Guarantees (or otherwise becomes liable for) any Obligations under any Credit Facility, including the Credit Agreement, then, within 20 Business Days after such date, such Domestic Subsidiary will unconditionally Guarantee the notes and concurrently become a Guarantor by executing a supplemental indenture in substantially the form specified in the indenture. Each Note Guarantee of a Guarantor will be released automatically at such time as such Guarantor is discharged or otherwise released from all its Obligations in respect of its Guarantee of (or other liability for) any Obligations under any Credit Facility; provided that such discharge or other release did not result directly from payment by such Guarantor in satisfaction of (a) its liability as a guarantor pursuant to such Guarantee, or (b) its primary liability for such Obligations (after demand or default under such Credit Facility). Furthermore, each Note Guarantee shall be subject to release as described under "—Note Guarantees."

        The Board of Directors of NGL Energy may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, the aggregate Fair Market Value of all outstanding Investments owned by NGL Energy and its Restricted Subsidiaries in the Subsidiary designated as an Unrestricted Subsidiary will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the covenant described above under the caption "—Covenants—Restricted Payments" or under one or more clauses of the definition of Permitted Investments, as determined by NGL Energy. That designation will only be permitted if the Investment would be permitted at that time and if the Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. The Board of Directors of NGL Energy may redesignate any Unrestricted Subsidiary to be a Restricted Subsidiary if that redesignation would not cause a Default.

        Any designation of a Subsidiary of NGL Energy as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee a certified copy of a resolution of the Board of Directors of NGL Energy giving effect to such designation and an Officers' Certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption "—Covenants—Restricted Payments." If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an

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Unrestricted Subsidiary for purposes of the indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption "—Incurrence of Indebtedness and Issuance of Preferred Stock," NGL Energy will be in default of such covenant.

        The Board of Directors of NGL Energy may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of any outstanding Indebtedness of such Unrestricted Subsidiary, and such designation will only be permitted if: (1) such Indebtedness is permitted under the covenant described under the caption "—Incurrence of Indebtedness and Issuance of Preferred Stock," calculated on a pro forma basis as if such designation had occurred at the beginning of the applicable reference period; and (2) no Default or Event of Default would be in existence following such designation.

        Regardless of whether required by the rules and regulations of the SEC, so long as any notes are outstanding, NGL Energy will file with the SEC (unless the SEC will not accept such a filing) within the time periods specified in the SEC's rules and regulations, and upon request, NGL Energy will furnish (without exhibits) to the trustee for delivery to the holders of the notes:

        NGL Energy will be deemed to have furnished such reports and information described above to the holders of Notes (and the trustee shall be deemed to have delivered such reports and information to the holders of the notes) if NGL Energy has filed such reports or information, respectively, with the SEC using the EDGAR filing system (or any successor filing system of the SEC) or, if the SEC will not accept such reports or information, if NGL Energy has posted such reports or information, respectively, on its website, and such reports or information, respectively, are available to holders of notes through internet access.

        For the avoidance of doubt, (a) such information will not be required to contain the separate financial information for Guarantors as contemplated by Rule 3-10 of Regulation S-X or any financial statements of unconsolidated subsidiaries or 50% or less owned Persons as contemplated by Rule 3-09 of Regulation S-X or any schedules required by Regulation S-X, or in each case any successor provisions, and (b) such information shall not be required to comply with Regulation G under the Exchange Act or Item 10(e) of Regulation S-K with respect to any non-GAAP financial measures contained therein.

        Except as provided above, all such reports will be prepared in all material respects in accordance with all of the rules and regulations applicable to such reports.

        If NGL Energy has designated any of its Subsidiaries as Unrestricted Subsidiaries, then, to the extent material, the quarterly and annual financial information required by the preceding paragraphs will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in Management's Discussion and Analysis of Financial Condition and Results of Operations, of the financial condition and results of operations of NGL Energy and its Restricted

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Subsidiaries separate from the financial condition and results of operations of its Unrestricted Subsidiaries.

        Any and all Defaults or Events of Default arising from a failure to furnish in a timely manner any financial information required by this covenant shall be deemed cured (and NGL Energy shall be deemed to be in compliance with this covenant) upon furnishing such financial information as contemplated by this covenant (but without regard to the date on which such financial statement or report is so furnished); provided that such cure shall not otherwise affect the rights of the holders under "—Events of Defaults and Remedies" if the principal of, premium, if any, on, and interest, if any, on, the notes have been accelerated in accordance with the terms of the indenture and such acceleration has not been rescinded or cancelled prior to such cure.

        In addition, NGL Energy will hold and participate in annual conference calls with the holders of the notes, beneficial owners of the notes, bona fide prospective investors, securities analysts and market makers to discuss the financial information required to be furnished pursuant to clause (1) above no later than ten Business Days after distribution of such financial information. NGL Energy shall be permitted to combine this conference call with any other conference call for other debt or equity holders or lenders.

        In addition, NGL Energy and the Guarantors agree that, for so long as any notes remain outstanding, if at any time they are not required to file with the SEC the reports required by the preceding paragraphs, they will furnish to the holders of notes and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Events of Default and Remedies

        Each of the following is an "Event of Default" with respect to the notes:

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and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $30.0 million or more; provided that if, prior to any acceleration of the notes, (i) any such default is cured or waived, (ii) any such acceleration of such Indebtedness is rescinded, or (iii) such Indebtedness is repaid, within a period of 10 Business Days from the continuation of such default beyond the applicable grace period or the occurrence of such acceleration, as the case may be, any Default or Event of Default (but not any acceleration of the notes) shall be automatically rescinded, so long as such rescission does not conflict with any judgment or decree;

        The indenture will provide that in the case of an Event of Default arising from certain events of bankruptcy or insolvency, with respect to NGL Energy, any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all then outstanding notes will become due and payable immediately without further action or notice. However, the effect of such provision may be limited by applicable law. If any other Event of Default occurs and is continuing, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding notes may declare all of the notes to be due and payable immediately by notice in writing to NGL Energy and, in case of a notice by holders, also to the trustee specifying the respective Event of Default and that it is a notice of acceleration.

        Holders of the notes may not enforce the indenture or the notes except as provided in the indenture. Subject to certain limitations, holders of a majority in aggregate principal amount of the then outstanding notes may direct the trustee in its exercise of any trust or power. The trustee may withhold from holders of the notes notice of any continuing Default or Event of Default if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal, interest or premium, if any.

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        Subject to the provisions of the indenture relating to the duties of the trustee, in case an Event of Default occurs and is continuing, the trustee will be under no obligation to exercise any of the rights or powers under the indenture at the request or direction of any holders of notes unless such holders have offered to the trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest, when due, no holder of a note may pursue any remedy with respect to the indenture or the notes unless:

        The holders of a majority in aggregate principal amount of the then outstanding notes by written notice to the trustee may, on behalf of the holders of all of the notes, rescind an acceleration and its consequences if the rescission would not violate any judgment or decree and if all existing Events of Default (except nonpayment of principal, interest or premium or Liquidated Damages, if any, that has become due solely because of the acceleration) have been cured or waived.

        The Issuers are required to deliver to the trustee annually a statement regarding compliance with the indenture. Within five Business Days of any executive officer of the General Partner or Finance Corp. becoming aware of any Default or Event of Default, the Issuers will be required to deliver to the trustee a statement specifying such Default or Event of Default.

No Personal Liability of Directors, Officers, Employees and Unitholders and No Recourse to General Partner

        None of the General Partner or any director, officer, partner, employee, incorporator, manager, unitholder or other owner of Capital Stock of the General Partner, the Issuers or any Guarantor, as such, will have any liability for any obligations of the Issuers or the Guarantors under the notes, the indenture, the Note Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.

Legal Defeasance and Covenant Defeasance

        The Issuers may at any time, at the option of their respective Board of Directors evidenced by a resolution set forth in an Officers' Certificate, elect to have all of their obligations discharged with respect to the outstanding notes and all obligations of the Guarantors discharged with respect to their Note Guarantees ("Legal Defeasance") except for:

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        In addition, the Issuers may, at their option and at any time, elect to have their obligations and the obligations of the Guarantors released with respect to the provisions of the indenture described above under "—Repurchase at the Option of Holders" and under "—Covenants" (other than the covenant described under "—Covenants—Merger, Consolidation or Sale of Assets," except to the extent described below) and the limitation imposed by clause (4) under "—Covenants—Merger, Consolidation or Sale of Assets" (such release and termination being referred to as "Covenant Defeasance"), and thereafter any failure to comply with such obligations or provisions will not constitute a Default or Event of Default with respect to the notes. In the event Covenant Defeasance occurs, the Events of Default described under clauses (3) through (7) under the caption "—Events of Default and Remedies" and the Event of Default described under clause (9) under the caption "—Events of Default and Remedies" (but only with respect to Subsidiaries of NGL Energy), in each case, will no longer constitute an Event of Default with respect to the notes. If the Issuers exercise either their Legal Defeasance or Covenant Defeasance option, each Guarantor will be released and relieved of any Obligations under the indenture, including its Obligations in respect of its Subsidiary Guarantee.

        In order to exercise either Legal Defeasance or Covenant Defeasance:

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Amendment, Supplement and Waiver

        Except as provided in the next three succeeding paragraphs, the indenture or the notes or the Note Guarantees may be amended or supplemented with the consent of the holders of at least a majority in aggregate principal amount of the then outstanding notes (including, without limitation, additional notes, if any) voting as a single class (including, without limitation, consents obtained in connection with a tender offer or exchange offer for, or purchase of, the notes), and any existing Default or Event of Default (other than a Default or Event of Default in the payment of the principal of, premium on, if any, interest or Special Interest, if any, on, the notes, except a payment default resulting from an acceleration that has been rescinded) or compliance with any provision of the indenture or the notes or the Note Guarantees may be waived with the consent of the holders of a majority in aggregate principal amount of the then outstanding notes (including, without limitation, additional notes, if any) voting as a single class (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes).

        Without the consent of each holder of notes affected, an amendment, supplement or waiver may not (with respect to any notes held by a non-consenting holder):

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        Notwithstanding the preceding, without the consent of any holder of notes, the Issuers, the Guarantors and the trustee may amend or supplement the indenture, the notes or the Note Guarantees:

        The consent of the holders is not necessary under the indenture to approve the particular form of any proposed amendment, supplement or waiver. It is sufficient if such consent approves the substance of the proposed amendment, supplement or waiver. After an amendment, supplement or waiver under the indenture requiring the approval of the holders becomes effective, NGL Energy will send to the holders a notice briefly describing the amendment, supplement or waiver. However, the failure to give such notice, or any defect in the notice, will not impair or affect the validity of the amendment, supplement or waiver.

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Satisfaction and Discharge

        The indenture will be satisfied and discharged and will cease to be of further effect as to all notes issued thereunder (except as to surviving rights of registration of transfer or exchange of the notes and as otherwise specified in the indenture), when:

        In addition, the Issuers must deliver (a) an Officers' Certificate, stating that all conditions precedent set forth in clauses (1) through (4) above have been satisfied and (b) an opinion of counsel, stating that the condition precedent set forth in clause (4) above has been satisfied.

Concerning the Trustee

        U.S. Bank National Association will be the trustee under the indenture.

        If the trustee becomes a creditor of either Issuer or any Guarantor, the indenture limits the right of the trustee to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest it must eliminate such conflict within 90 days, apply to the SEC for permission to continue as trustee (if the indenture has been qualified under the Trust Indenture Act) or resign.

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        The holders of a majority in aggregate principal amount of the then outstanding notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. The indenture provides that in case an Event of Default has occurred and is continuing, the trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the indenture at the request of any holder of notes, unless such holder has offered to the trustee reasonable indemnity or security satisfactory to it against any loss, liability or expense.

Governing Law

        The indenture, the notes and the Note Guarantees will be governed by, and construed in accordance with, the laws of the State of New York.

Book-Entry, Delivery and Form

        The new notes will be issued initially only in the form of one or more global notes (collectively, the "Global Notes"). The Global Notes will be deposited upon issuance with the trustee as custodian for The Depository Trust Company ("DTC"), in New York, New York, and registered in the name of DTC's nominee, Cede & Co., in each case for credit to an account of a direct or indirect participant in DTC as described below. Beneficial interests in the Global Notes may be held through the Euroclear System ("Euroclear") and Clearstream Banking, S.A. ("Clearstream") (as indirect participants in DTC).

        The Global Notes may be transferred, in whole but not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for notes in registered, certificated form ("Certificated Notes") except in the limited circumstances described below. See "—Exchange of Global Notes for Certificated Notes."

        In addition, transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.

Depository Procedures

        The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. The Issuers take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

        DTC has advised the Issuers that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the "Participants") and to facilitate the clearance and settlement of transactions in those securities between the Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC's system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the "Indirect Participants"). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

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        DTC has also advised the Issuers that, pursuant to procedures established by it:

        Except as described below, beneficial owners of interests in the Global Notes will not have notes registered in their names, will not receive physical delivery of Certificated Notes and will not be considered the registered owners or "holders" thereof under the indenture for any purpose.

        Payments in respect of the principal of, and interest and premium, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the indenture. Under the terms of the indenture, the Issuers, the Guarantors and the trustee will treat the Persons in whose names the notes, including the Global Notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes. Consequently, neither the Issuers, the Guarantors, the trustee nor any agent of the Issuers, the Guarantors or the trustee has or will have any responsibility or liability for:

        DTC has advised the Issuers that its current practice, upon receipt of any payment in respect of securities such as the notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe that it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee, the Issuers or the Guarantors. None of the Issuers, the Guarantors nor the trustee will be liable for any delay by DTC or any of the Participants or the Indirect Participants in identifying the beneficial owners of the notes, and the Issuers, the Guarantors and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

        Subject to the transfer restrictions set forth under "Notice to Investors," transfers between the Participants will be effected in accordance with DTC's procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

        Subject to compliance with the transfer restrictions applicable to the notes described herein, cross-market transfers between the Participants, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC's rules on behalf of Euroclear or Clearstream, as the case may be, by their respective depositaries; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the

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established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to

        its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositaries for Euroclear or Clearstream.

        DTC has advised the Issuers that it will take any action permitted to be taken by a holder of notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for Certificated Notes, and to distribute such notes to its Participants.

Exchange of Global Notes for Certificated Notes

        A Global Note is exchangeable for Certificated Notes if:

        In addition, beneficial interests in a Global Note may be exchanged for Certificated Notes upon prior written notice given to the trustee by or on behalf of DTC in accordance with the indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear the applicable restrictive legend referred to in "Notice to Investors," unless that legend is not required by applicable law.

Exchange of Certificated Notes for Global Notes

        Certificated Notes may not be exchanged for beneficial interests in any Global Note unless the transferor first delivers to the trustee a written certificate (in the form provided in the indenture) to the effect that such transfer will comply with the appropriate transfer restrictions applicable to such notes. See "Notice to Investors."

Same Day Settlement and Payment

        The Issuers will make payments in respect of the notes represented by the Global Notes (including principal, premium, if any, and interest) by wire transfer of immediately available funds to the accounts specified by DTC or its nominee. The Issuers will make all payments of principal, interest and premium, if any, with respect to Certificated Notes in the manner described above under "—Methods of Receiving Payments on the Notes." The notes represented by the Global Notes are expected to trade in DTC's Same-Day Funds Settlement System, and any permitted secondary market trading activity in such notes will, therefore, be required by DTC to be settled in immediately available funds.

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The Issuers expect that secondary trading in any Certificated Notes will also be settled in immediately available funds.

        Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a Global Note from a Participant will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised the Issuers that cash received in Euroclear or Clearstream as a result of sales of interests in a Global Note by or through a Euroclear or Clearstream participant to a Participant will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC's settlement date.

Definitions

        "Acquired Debt" means, with respect to any specified Person:

        "Additional Assets" means:

provided, however, that, in the case of clauses (2) and (3), such Restricted Subsidiary is primarily engaged in a Permitted Business.

        "Affiliate" of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, "control," as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise. For purposes of this definition, the terms "controlling," "controlled by" and "under common control with" have correlative meanings.

        "Asset Sale" means:

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        Notwithstanding the preceding, none of the following items will be deemed to be an Asset Sale:

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        "Available Cash" has the meaning assigned to such term in the Partnership Agreement, as in effect on the Issue Date.

        "Beneficial Owner" has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular "person" (as that term is used in Section 13(d)(3) of the Exchange Act), such "person" will be deemed to have beneficial ownership of all securities that such "person" has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only after the passage of time. The terms "Beneficially Owns" and "Beneficially Owned" have corresponding meanings. For purposes of this definition, a Person shall be deemed not to Beneficially Own securities that are the subject of a stock purchase agreement, merger agreement, amalgamation agreement, arrangement agreement or similar agreement until consummation of the transactions or, as applicable, series of related transactions contemplated thereby.

        "Board of Directors" means:

        So long as NGL Energy is organized as a limited partnership, references to its Board of Directors are to the Board of Directors of the General Partner.

        "Business Day" means each day that is not a Saturday, Sunday or other day on which banking institutions in New York, New York or another place of payment are authorized or required by law to remain closed.

        "Capital Lease Obligation" means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet prepared in accordance with GAAP, and the Stated Maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be prepaid by the lessee without payment of a penalty. Notwithstanding the foregoing, any lease (whether entered into before or after the Issue Date) that would have been classified as an operating lease pursuant to GAAP as in effect on the Issue Date will be deemed not to represent a Capital Lease Obligation, notwithstanding any change in GAAP that occurs after the Issue Date.

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        "Capital Stock" means:

        "Cash Equivalents" means:

        "Change of Control" means the occurrence of any of the following:

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        Notwithstanding the preceding, a conversion of NGL Energy or any of its Restricted Subsidiaries from a limited partnership, corporation, limited liability company or other form of entity to a limited liability company, corporation, limited partnership or other form of entity or an exchange of all of the outstanding Equity Interests in one form of entity for Equity Interests in another form of entity shall not constitute a Change of Control, so long as following such conversion or exchange the "persons" (as that term is used in Section 13(d)(3) of the Exchange Act) who Beneficially Owned the Capital Stock of NGL Energy immediately prior to such transactions continue to Beneficially Own in the aggregate more than 50% of the Voting Stock of such entity, or continue to Beneficially Own sufficient Equity Interests in such entity or its general partner, as applicable, to elect a majority of its directors, managers, trustees or other persons serving in a similar capacity for such entity or its general partner, as applicable, and, in either case, no "person," other than a Permitted Holder, Beneficially Owns more than 50% of the Voting Stock of such entity or its general partner, as applicable.

        "Consolidated Cash Flow" means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period plus, without duplication:

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        "Consolidated Net Income" means, with respect to any specified Person for any period, the aggregate of the net income (loss) of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP and without any reduction in respect of preferred stock dividends; provided that:

        "continuing" means, with respect to any Default or Event of Default, that such Default or Event of Default has not been cured or waived.

        "Credit Agreement" means that certain Credit Agreement, dated as of June 19, 2012, by and among NGL Energy, the subsidiary borrowers party thereto, NGL Energy Operating LLC, as borrowers' agent, the lenders party thereto, Deutsche Bank AG, New York Branch, as technical agent, and Deutsche Bank Trust Company Americas, as administrative agent and as collateral agent, as amended by the Facility Increase Agreement, dated November 1, 2012, Amendment No. 1 to Credit Agreement, dated as of January 15, 2013 and Amendment No. 2 to Credit Agreement, dated as of May 8, 2013, including

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any related notes, Guarantees, collateral documents, instruments and agreements executed in connection therewith, and, in each case, as amended, restated, modified, renewed, refunded, replaced in any manner (whether upon or after termination or otherwise) or refinanced (including by means of sales of debt securities to institutional investors) in whole or in part from time to time.

        "Credit Facilities" means one or more debt facilities (including, without limitation, any Credit Agreement), commercial paper facilities or secured or unsecured capital markets financings, in each case, with banks or other institutional lenders or institutional investors providing for revolving credit loans, term loans, capital market financings, private placements, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, in each case, as amended, restated, modified, renewed, refunded, replaced in any manner (whether upon or after termination or otherwise) or refinanced (including refinancing with any capital markets transaction or otherwise by means of sales of debt securities to institutional investors) in whole or in part from time to time.

        "Customary Recourse Exceptions" means, with respect to any Non-Recourse Debt of an Unrestricted Subsidiary or Joint Venture, (i) Liens on and pledges of the Equity Interests of any Unrestricted Subsidiary or any Joint Venture owned by NGL Energy or any Restricted Subsidiary to the extent securing otherwise Non-Recourse Debt of such Unrestricted Subsidiary or Joint Venture and (ii) exclusions from the exculpation provisions with respect to such Non-Recourse Debt for the voluntary bankruptcy of such Unrestricted Subsidiary or Joint Venture, fraud, misapplication of cash, environmental claims, waste, willful destruction and other circumstances customarily excluded by lenders from exculpation provisions or included in separate indemnification agreements in non-recourse financings.

        "Default" means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

        "Disqualified Stock" means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the notes mature. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require NGL Energy to repurchase or redeem such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if the terms of such Capital Stock provide that NGL Energy may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption "—Covenants—Restricted Payments." The amount of Disqualified Stock deemed to be outstanding at any time for purposes of the indenture will be the maximum amount that NGL Energy and its Restricted Subsidiaries may become obligated to pay upon the maturity of, or pursuant to any mandatory redemption provisions of, such Disqualified Stock, exclusive of accrued dividends.

        "Domestic Subsidiary" means any Restricted Subsidiary that was formed under the laws of the United States or any state of the United States or the District of Columbia or that guarantees or otherwise provides direct credit support for any Indebtedness of NGL Energy or any Restricted Subsidiary (other than a Foreign Subsidiary).

        "Equity Interests" of any Person means Capital Stock and all warrants, options or other rights to acquire Capital Stock of such Person (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

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        "Equity Offering" means a sale of Equity Interests of NGL Energy (other than Disqualified Stock and other than to a Subsidiary of NGL Energy) made for cash on a primary basis by NGL Energy after the Issue Date.

        "Exchange Notes" means an issue of notes with terms identical to the notes (except that the Exchange Notes will not be subject to restrictions on transfer, registration rights or Liquidated Damages) issued in an Exchange Offer pursuant to the indenture.

        "Exchange Act" means the Securities Exchange Act of 1934, as amended.

        "Existing Indebtedness" means all Indebtedness of NGL Energy and its Subsidiaries (other than Indebtedness under the Credit Agreement, the notes or the Note Guarantees) in existence on the Issue Date, until such amounts are repaid.

        "Existing Senior Secured Notes" means NGL Energy's $250,000,000 aggregate principal amount of 6.65% Senior Secured Notes due June 19, 2022.

        "Fair Market Value" means the value that would be paid by a willing buyer to an unaffiliated willing seller in a transaction not involving distress or necessity of either party, determined in good faith by the Board of Directors of NGL Energy in the case of amounts of $40.0 million or more and otherwise by an officer of the General Partner (unless otherwise provided in the indenture).

        "FASB ASC 815" means Financial Accounting Standards Board Accounting Standards Codification 815.

        "FERC Subsidiary" means a Restricted Subsidiary that is subject to the regulatory jurisdiction of the Federal Energy Regulatory Commission (or any successor thereof).

        "Fitch" means Fitch Ratings, Inc. or any successor to the ratings business thereof.

        "Fixed Charge Coverage Ratio" means with respect to any specified Person for any four-quarter reference period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, Guarantees, repays, repurchases, redeems, defeases or otherwise discharges any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems preferred stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the "Calculation Date"), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, Guarantee, repayment, repurchase, redemption, defeasance or other discharge of Indebtedness, or such issuance, repurchase or redemption of preferred stock, and the use of the proceeds therefrom, as if the same had occurred at the beginning of the applicable four-quarter reference period. If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the average rate in effect from the beginning of such period to the Calculation Date had been the applicable rate for the entire period (taking into account any interest Hedging Obligation applicable to such Indebtedness, but if the remaining term of such interest Hedging Obligation is less than twelve months, then such interest Hedging Obligation shall only be taken into account for that portion of the period equal to the remaining term thereof). If any Indebtedness that is being given pro forma effect bears an interest rate at the option of such Person, the interest rate shall be calculated by applying such option rate chosen by such Person. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a Eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or if none, then based upon such optional rate chosen as such Person may designate.

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        In addition, for purposes of calculating the Fixed Charge Coverage Ratio:

        For purposes of this definition, whenever pro forma effect is to be given to any calculation under this definition, the pro forma calculations will be determined in good faith by a responsible financial or accounting officer of such Person, which determination shall be conclusive for all purposes under the indenture; provided that such officer may in such officer's discretion include any reasonably identifiable and factually supportable pro forma changes to Consolidated Cash Flow or Fixed Charges, including any pro forma expense and cost reductions or synergies that have occurred or are reasonably expected to occur within the 12 months immediately following the Calculation Date and are either (i) prepared and calculated in accordance with Regulation S-X under the Securities Act or (ii) set forth in an Officers' Certificate signed by the chief financial officer of such Person that states (a) the amount of each such adjustment and (b) that such adjustments are based on the reasonable good faith belief of the chief financial officer executing such Officers' Certificate at the time of such execution and the factual basis on which such good faith belief is based.

        "Fixed Charges" means, with respect to any specified Person for any period, the sum, without duplication, of:

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        "Foreign Subsidiary" means any Restricted Subsidiary that is not a Domestic Subsidiary.

        "GAAP" means generally accepted accounting principles in the United States, that are in effect from time to time. All ratios and computations based on GAAP contained in the indenture will be computed in conformity with GAAP. At any time after the Issue Date, NGL Energy may elect to apply International Financial Reporting Standards ("IFRS") accounting principles in lieu of GAAP and, upon any such election, references herein to GAAP shall thereafter be construed to mean IFRS (except as otherwise provided in the indenture); provided that any such election, once made, shall be irrevocable; provided, further, that any calculation or determination in the indenture that requires the application of GAAP for periods that include fiscal quarters ended prior to NGL Energy's election to apply IFRS shall remain as previously calculated or determined in accordance with GAAP. NGL Energy shall give notice of any such election made in accordance with this definition to the trustee and the holders of notes.

        "General Partner" means NGL Energy Holdings LLC, a Delaware limited liability company, and its successors and permitted assigns as the general partner of NGL Energy.

        "Government Securities" means direct obligations of, or obligations Guaranteed by, the United States of America, and the payment for which the United States pledges its full faith and credit.

        "Guarantee" means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services, to take or pay or to maintain financial statement conditions or otherwise). When used as a verb, "Guarantee" has a correlative meaning.

        "Guarantors" means any of: (1) the Subsidiaries of NGL Energy, other than Finance Corp., executing the indenture as initial Guarantors; and (2) the Restricted Subsidiaries of NGL Energy that become Guarantors in accordance with the provisions of the indenture, and their respective successors and assigns, in each case, until the Note Guarantee of such Person has been released in accordance with the provisions of the indenture.

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        "Hedging Obligations" means, with respect to any specified Person, the obligations of such Person under:

        "Hydrocarbons" means oil, natural gas, casing head gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

        "Indebtedness" means, with respect to any specified Person, without duplication, any indebtedness of such Person, regardless of whether contingent:

        if and to the extent any of the preceding items (other than letters of credit and Hedging Obligations) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term "Indebtedness" includes (a) all Indebtedness of others secured by a Lien on any asset of the specified Person (regardless of whether such Indebtedness is assumed by the specified Person); provided, that the amount of such Indebtedness will be the lesser of (i) the Fair Market Value of such asset at such date of determination and (ii) the amount of such Indebtedness of such other Person, and (b) to the extent not otherwise included, the Guarantee by the specified Person of any Indebtedness of any other Person. Indebtedness shall be calculated without giving effect to the effects of FASB ASC 815 and related interpretations to the extent such effects would otherwise increase or decrease an amount of Indebtedness for any purpose under the indenture as a result of accounting for any embedded derivatives created by the terms of such Indebtedness.

        The amount of any Indebtedness outstanding as of any date will be:

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        Notwithstanding the foregoing, the following shall not constitute "Indebtedness:"

        "Investment Grade Rating" means a rating equal to or higher than:

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or, if any such Rating Agency ceases to rate the notes for reasons outside of the control of NGL Energy, the equivalent investment grade credit rating from any other Rating Agency.

        "Investment Grade Rating Event" means the first day on which (a) the notes have an Investment Grade Rating from at least two Rating Agencies, (b) no Default with respect to the notes has occurred and is then continuing under the indenture and (c) NGL Energy has delivered to the trustee an Officers' Certificate certifying as to the satisfaction of the conditions set forth in clauses (a) and (b) of this definition.

        "Investments" means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including Guarantees or other obligations), advances or capital contributions (excluding (1) endorsements of negotiable instruments and documents in the ordinary course of business, and commission, travel and similar advances to officers, employees and consultants made in the ordinary course of business and (2) advances to customers in the ordinary course of business that are recorded as accounts receivable on the balance sheet of the Person making the advance), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities (excluding any interest in an oil or natural gas leasehold to the extent constituting a security under applicable law), together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If NGL Energy or any Restricted Subsidiary sells or otherwise disposes of any Equity Interests of any Restricted Subsidiary such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary of NGL Energy, NGL Energy will be deemed to have made an Investment on the date of any such sale or disposition in an amount equal to the Fair Market Value of NGL Energy's Investments in such Subsidiary that were not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption "—Covenants—Restricted Payments." The acquisition by NGL Energy or any Restricted Subsidiary of a Person that holds an Investment in a third Person will be deemed to be an Investment by NGL Energy or such Restricted Subsidiary in such third Person in an amount equal to the Fair Market Value of the Investments held by the acquired Person in such third Person in an amount determined as provided in the final paragraph of the covenant described above under the caption "—Covenants—Restricted Payments." Except as otherwise provided in the indenture, the amount of an Investment will be determined at the time the Investment is made and without giving effect to subsequent changes in value or write-ups, write-downs or write-offs with respect to such Investment.

        "Issue Date" means the first date on which notes are issued under the indenture.

        "Joint Venture" means any Person that is not a direct or indirect Subsidiary of NGL Energy in which NGL Energy or any of its Restricted Subsidiaries makes any Investment.

        "Lien" means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, regardless of whether filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction other than a precautionary financing statement respecting a lease not intended as a security agreement.

        "Moody's" means Moody's Investors Service, Inc. or any successor to the ratings business thereof.

        "Net Proceeds" means the aggregate amount of cash proceeds and Cash Equivalents received by NGL Energy or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without

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limitation, any cash or Cash Equivalents received upon the sale or other disposition of any non-cash consideration received in any Asset Sale, but excluding any non-cash consideration deemed to be cash for purposes of the "Asset Sales" provisions of the indenture), net of:

        "Non-Recourse Debt" means Indebtedness:

        "Note Guarantee" means any Guarantee of the Issuers' obligations under the indenture and the notes by any Guarantor in accordance with the provisions of the indenture.

        "Obligations" means any principal, interest, penalties, fees, indemnifications, reimbursements, damages and other liabilities payable under the documentation governing any Indebtedness.

        "Officer" means, with respect to any Person, the Chairman of the Board, the Chief Executive Officer, the President, the Chief Operating Officer, the Chief Financial Officer, the Chief Accounting Officer, the Treasurer, any Assistant Treasurer, the Controller, the Secretary or any Vice-President of such Person (or, with respect to NGL Energy, so long as it remains a partnership, the General Partner).

        "Officers' Certificate" means a certificate signed on behalf of NGL Energy by two Officers of NGL Energy or two Officers of the General Partner, one of whom must be the principal executive officer, the principal financial officer or the principal accounting officer of such Person, that meets the requirements of the indenture pertaining to such certificates.

        "Operating Surplus" has the meaning assigned to such term in the Partnership Agreement, as in effect on the Issue Date.

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        "Partnership Agreement" means the Second Amended and Restated Agreement of Limited Partnership of NGL Energy dated as of May 10, 2011, as amended by the First Amendment thereto dated as of October 20, 2011, the Second Amendment thereto dated as of January 6, 2012, the Third Amendment thereto dated as of January 20, 2012 and the Fourth Amendment thereto dated as of July 11, 2012, as such may be further amended, modified or supplemented from time to time.

        "Permitted Acquisition Indebtedness" means Indebtedness or Disqualified Stock of NGL Energy or any of its Restricted Subsidiaries to the extent such Indebtedness or Disqualified Stock was Indebtedness or Disqualified Stock of:

provided that on the date such Subsidiary became a Restricted Subsidiary or the date such Person was merged and consolidated into NGL Energy or a Restricted Subsidiary, as applicable, after giving pro forma effect thereto and to any related financing transaction as if the same had occurred at the beginning of the applicable four-quarter period:

        "Permitted Business" means either (a) gathering, transporting, compressing, treating, processing, marketing, distributing, storing or otherwise handling Hydrocarbons, or activities or services reasonably related or ancillary thereto, including water treatment, disposal and transportation, and entering into Hedging Obligations relating to any of the foregoing activities, or (b) any other business that generates gross income at least 90% of which constitutes "qualifying income" under Section 7704(d) of the Internal Revenue Code.

        "Permitted Business Investments" means Investments by NGL Energy or any of its Restricted Subsidiaries in any Unrestricted Subsidiary or in any Joint Venture; provided that:

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        "Permitted Debt" is defined in the covenant described under the caption "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock."

        "Permitted Holder" means: (i) any of Coady Enterprises, LLC, Shawn W. Coady, Thorndike, LLC, Todd M. Coady, SemGroup Corporation, KrimGP2010, LLC, H. Michael Krimbill, EMG I NGL GP Holdings, LLC and EMG II NGL GP Holdings, LLC; (ii) any wife, lineal descendant, legal guardian or other legal representative or estate of any of the Persons described in the preceding clause (i); (iii) any trust of which at least one of the trustees is any of the Persons described in the preceding clauses (i) or (ii); and (iv) any other Person that is controlled directly or indirectly by any one or more of the Persons described in the preceding clauses (i) through (iii). As of the Issue Date, (i) Shawn W. Coady is our President and Chief Operating Officer, Retail Division, (ii) Todd M. Coady is our Vice President, Administration and (iii) H. Michael Krimbill is our Chief Executive Officer and a member of our Board of Directors.

        "Permitted Investments" means:

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        "Permitted Liens" means, with respect to any Person:

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        "Permitted Refinancing Indebtedness" means any Indebtedness of NGL Energy or any of its Restricted Subsidiaries, any Disqualified Stock of NGL Energy or any preferred stock of any Restricted Subsidiary (a) issued in exchange for, or the net proceeds of which are used to extend, renew, refund, refinance, replace, defease, discharge or otherwise retire for value, in whole or in part, or (b) constituting an amendment, modification or supplement to or a deferral or renewal of (clauses (a) and (b), collectively, a "Refinancing," and the term "Refinanced" has a correlative meaning) any other Indebtedness of NGL Energy or any of its Restricted Subsidiaries (other than intercompany Indebtedness), any Disqualified Stock of NGL Energy or any preferred stock of a Restricted Subsidiary in a principal amount or, in the case of Disqualified Stock of NGL Energy or preferred stock of a Restricted Subsidiary, liquidation preference, not to exceed (after deduction of reasonable and customary fees and expenses incurred in connection with the Refinancing) the lesser of:

        Notwithstanding the preceding, no Indebtedness, Disqualified Stock or preferred stock will be deemed to be Permitted Refinancing Indebtedness, unless:

        Notwithstanding the foregoing, any Indebtedness incurred under Credit Facilities shall be subject to the refinancing provision of the definition of Credit Facilities and not pursuant to the requirements set forth in this definition of Permitted Refinancing Indebtedness. "Person" means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

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        "Rating Agency" means each of S&P, Moody's and Fitch, or if (and only if) any of S&P, Moody's or Fitch shall not make a rating on the notes publicly available, a nationally recognized statistical rating agency or agencies, as the case may be, selected by NGL Energy, which shall be substituted for S&P, Moody's or Fitch, as the case may be.

        "Reporting Default" means a Default described in subclause (b) of clause (5) under "—Events of Default and Remedies."

        "Restricted Investment" means an Investment other than a Permitted Investment.

        "Restricted Subsidiary" means any Subsidiary of NGL Energy, other than an Unrestricted Subsidiary.

        "S&P" means Standard & Poor's Ratings Services, a division of The McGraw-Hill Companies, Inc., or any successor to the rating business thereof.

        "SEC" means the United States Securities and Exchange Commission.

        "Securities Act" means the Securities Act of 1933, as amended.

        "Senior Debt" means:

Notwithstanding anything to the contrary in the preceding sentence, Senior Debt will not include:

        "Significant Subsidiary" means any Restricted Subsidiary that would be a "significant subsidiary" as defined in Article 1, Rule 1-02 of Regulation S-X promulgated pursuant to the Securities Act, as such Regulation is in effect on the Issue Date.

        "Stated Maturity" means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the documentation governing such Indebtedness as of the first date it was incurred in compliance with the terms of the indenture, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof; provided that, in the case of debt securities that are by their terms convertible into Capital Stock (or cash or a combination of cash and Capital Stock based on the value of the Capital Stock) of NGL Energy, any obligation to offer to repurchase such debt securities on a date(s) specified in the original terms of such securities, which obligation is not subject to any condition or contingency, will be treated as a Stated Maturity date of such convertible debt securities.

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        "Subordinated Debt" means Indebtedness of NGL Energy or a Guarantor that is contractually subordinated in right of payment (by its terms or the terms of any document or instrument relating thereto) to the notes or the Note Guarantee of such Guarantor, as applicable.

        "Subsidiary" means, with respect to any specified Person:

        "Total Assets" of any Person means, as of any date, the amount that, in accordance with GAAP, would be set forth under the caption "Total Assets" (or any like caption) on a consolidated balance sheet of such Person and its Restricted Subsidiaries, as of the end of the most recently ended fiscal quarter for which internal financial statements are available; provided, however that such amount shall be adjusted to give pro forma effect to any subsequent Investment, acquisition or disposition of any assets or Person (regardless of whether effected as a merger, purchase or sale of Equity Interests, asset acquisition or disposition or other form of acquisition or disposition) by such Person or any of its Restricted Subsidiaries, including any such Investment, acquisition or disposition that is pending and giving rise to the need to determine the amount of Total Assets, as if such transaction had occurred immediately prior to the end of such most recently ended fiscal quarter.

        "Treasury Management Arrangement" means any agreement or other arrangement governing the provision of treasury or cash management services, including deposit accounts, overdraft, credit or debit card, funds transfer, automated clearinghouse, zero balance accounts, returned check concentration, controlled disbursement, lockbox, account reconciliation and reporting and trade finance services and other cash management services.

        "Unrestricted Subsidiary" means any Subsidiary of NGL Energy (excluding Finance Corp.) that is designated by the Board of Directors of NGL Energy as an Unrestricted Subsidiary pursuant to a resolution of the Board of Directors, but only to the extent that such Subsidiary:

        All Subsidiaries of an Unrestricted Subsidiary shall also be Unrestricted Subsidiaries.

        "Voting Stock" of any specified Person as of any date means the Capital Stock of such Person entitling the holders thereof (whether at all times or only so long as no senior class of Capital Stock

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has voting power by reason of any contingency) to vote in the election of members of the Board of Directors of such Person; provided that, with respect to a limited partnership or other entity which does not have a Board of Directors, Voting Stock means the Capital Stock of the general partner of such limited partnership or other business entity with the ultimate authority to manage the business and operations of such Person.

        "Weighted Average Life to Maturity" means, when applied to any Indebtedness at any date, the number of years obtained by dividing:

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PLAN OF DISTRIBUTION

        Each broker-dealer that receives New Notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such New Notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the consummation of the exchange offer, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until                         , 2014, all dealers effecting transactions in the new notes may be required to deliver a prospectus.

        We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the new notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes. Any broker-dealer that resells new notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such new notes may be deemed to be an "underwriter" within the meaning of the Securities Act and any profit on any such resale of new notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

        For a period of 180 days after the consummation of the exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all reasonable expenses incident to the exchange offer (including the reasonable expenses of one counsel for the holders of the notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

        Following completion of the exchange offer, we may, in our sole discretion, commence one or more additional exchange offers to holders of old notes who did not exchange their old notes for new notes in the exchange offer on terms which may differ from those contained in this prospectus and the enclosed letter of transmittal. This prospectus, as it may be amended or supplemented from time to time, may be used by us in connection with any additional exchange offers. These additional exchange offers may take place from time to time until all outstanding old notes have been exchanged for new notes, subject to the terms and conditions in the prospectus and letter of transmittal distributed by us in connection with these additional exchange offers.

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CERTAIN U.S. FEDERAL INCOME TAX CONSEQUENCES

        The following discussion is a summary of certain U.S. federal income tax considerations relevant to the exchange of old notes for new notes, but does not purport to be a complete analysis of all potential tax effects. The discussion is based upon the Internal Revenue Code of 1986, as amended, Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of new notes. We cannot assure you that the Internal Revenue Service will not challenge one or more of the tax consequences described in this discussion, and we have not obtained, nor do we intend to obtain, a ruling from the Internal Revenue Service or an opinion of counsel with respect to the U.S. federal tax consequences described herein. Some holders, including financial institutions, insurance companies, regulated investment companies, tax-exempt organizations, dealers in securities or currencies, persons whose functional currency is not the U.S. dollar or persons who hold the notes as part of a hedge, conversion transaction, straddle or other risk reduction transaction may be subject to special rules not discussed below.

        We recommend that each holder consult his own tax advisor as to the particular tax consequences of exchanging such holder's old notes for new notes, including the applicability and effect of any foreign, state, local or other tax laws or estate or gift tax considerations.

        We believe that the exchange of old notes for new notes will not be a taxable exchange to a holder for U.S. federal income tax purposes. Accordingly, a holder will not recognize gain or loss upon receipt of a new note in exchange for an old note in the exchange, and the holder's basis and holding period in the new note will be the same as its basis and holding period in the corresponding old note immediately before the exchange.

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LEGAL MATTERS

        The validity of the new notes offered in this exchange offer will be passed on by Andrews Kurth LLP, Houston, Texas. Certain matters with respect to Colorado law will be passed upon by William G. Laughlin, Denver, Colorado, internal counsel to NGL Energy Partners LP. Certain matters with respect to Wyoming law will be passed upon by Holland & Hart LLP, Cheyenne, Wyoming. Certain matters with respect to Oklahoma law will be passed upon by Wilkin / McMurray PLLC, Tulsa, Oklahoma. Certain matters with respect to Alberta law will be passed upon by Norton Rose Fulbright Canada LLP, Calgary, Alberta.

EXPERTS

        Management's assessment of the effectiveness of internal control over financial reporting of NGL Energy Partners LP included in the Partnership's Annual Report on Form 10-K which is included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

        The audited consolidated financial statements of NGL Energy Partners LP and subsidiaries as of March 31, 2014 and 2013 and for each of the three years ended March 31, 2014 included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

        The consolidated financial statements of High Sierra Energy GP, LLC and subsidiaries as of December 31, 2011 and 2010 and for each of the three years in the period ended December 31, 2011 included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

        The financial statements of SemStream, L.P. Non-Residential Division as of December 31, 2010 and 2009 and for the year ended December 31, 2010, and for the one month ended December 31, 2009 (Subsequent to Emergence), and for the eleven months ended November 30, 2009, and for the year ended December 31, 2008 (Prior to Emergence), included in this prospectus, have been so included in reliance on the report of BDO USA, LLP, an independent registered public accounting firm, appearing elsewhere herein, given upon the authority of said firm as experts in auditing and accounting.

        The combined financial statements of the Businesses of the Osterman Associated Companies Contributed to NGL Energy Partners LP as of September 30, 2011 and 2010 and for each of the three years in the period ended September 30, 2011, included in this prospectus, have been audited by Graham Shepherd, PC, independent certified public accountants, as stated in their report included herein. Such financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

        The audited combined financial statements of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, LLC, Toro Operating Company, Inc., and Striker Oilfield Services, LLC as of December 31, 2011 and for the three years then ended, included in this prospectus, have been audited by EKS&H, LLLP, independent certified public accountants, as stated in their report included herein. The condensed combined financial statements of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, LLC, Midstream Operations, LLC, Toro Operating Company, Inc., and Striker Oilfield Services, LLC as of September 30, 2012 and for the nine months ended September 30, 2012 and 2011, included in this prospectus, have been reviewed by EKS&H, LLLP, independent certified public accountants, as stated in their report included herein.

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Such financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

        The consolidated financial statements of Oilfield Water Lines, LP as of December 31, 2012 and for the period from inception (August 6, 2012) to December 31, 2012, the financial statements of High Roller Wells Pearsall SWD No. 1, Ltd. for the period from January 1, 2012 through August 28, 2012, the financial statements of High Roller Wells Karnes SWD No. 1, Ltd. for the period from inception (March 14, 2012) through December 4, 2012, and the financial statements of Lotus Oilfield Services, LLC for the period from January 1, 2012 to December 27, 2012, all of which are included in this prospectus, have been so included in reliance on the report of BDO USA, LLP, an independent registered public accounting firm, appearing elsewhere herein, given upon the authority of said firm as experts in auditing and accounting.

        The combined financial statements of Gavilon Energy (The Energy Business Units of Gavilon, LLC) as of December 31, 2012 and 2011, and the related combined statements of operations, comprehensive income (loss), equity and cash flows for each of the years in the three-year period ended December 31, 2012, have been included herein in reliance upon the report of KPMG, LLP, independent auditors, included herein and upon the authority of said firm as experts in accounting and auditing. NGL Energy Partners LP has agreed to indemnify and hold KPMG LLP (KPMG) harmless against and from any and all legal costs and expenses incurred by KPMG in successful defense of any legal action or proceeding that arises as a result of KPMG's consent to the inclusion of its audit report on the past financial statements of Gavilon Energy (The Energy Business Units of Gavilon, LLC) included in this registration statement.

        The combined financial statements of Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP as of and for the years ended December 31, 2013 and 2012, included in this Prospectus have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report appearing herein, and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

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INDEX TO FINANCIAL STATEMENTS

Audited Consolidated Financial Statements of NGL Energy Partners LP and Subsidiaries as of March 31, 2014 and 2013 and for Each of the Three Years Ended March 31, 2014

       

Report of Independent Registered Public Accounting Firm

   
F-5
 

Report of Independent Registered Public Accounting Firm

    F-6  

Consolidated Balance Sheets at March 31, 2014 and 2013

    F-8  

Consolidated Statements of Operations for the years ended March 31, 2014, 2013, and 2012

    F-9  

Consolidated Statements of Comprehensive Income for the years ended March 31, 2014, 2013, and 2012

    F-10  

Consolidated Statements of Changes in Equity for the years ended March 31, 2014, 2013, and 2012

    F-11  

Consolidated Statements of Cash Flows for the years ended March 31, 2014, 2013, and 2012

    F-12  

Notes to Consolidated Financial Statements

    F-13  

Unaudited Condensed Consolidated Financial Statements of NGL Energy Partners LP and Subsidiaries as of September 30, 2014 and for the Three Months and Six Months Ended September 30, 2014

   
 
 

Unaudited Condensed Consolidated Balance Sheets

   
F-80
 

Unaudited Condensed Consolidated Statements of Operations

    F-81  

Unaudited Condensed Consolidated Statements of Comprehensive Loss

    F-82  

Unaudited Condensed Consolidated Statement of Changes in Equity

    F-83  

Unaudited Condensed Consolidated Statements of Cash Flows

    F-84  

Notes to Unaudited Condensed Consolidated Financial Statements

    F-85  

Consolidated Financial Statements of High Sierra Energy GP, LLC and Subsidiaries as of December 31, 2011 and 2010 and for Each of the Three Years in the Period Ended December 31, 2011

   
 
 

Report of Independent Certified Public Accountants

   
F-142
 

Consolidated Balance Sheets

    F-143  

Consolidated Statements of Operations

    F-144  

Consolidated Statements of Equity

    F-145  

Consolidated Statements of Cash Flows

    F-146  

Notes to the Consolidated Financial Statements

    F-147  

Financial Statements of SemStream, L.P. Non-Residential Division as of December 31, 2010 and 2009 and for the Year Ended December 31, 2010, and for the One Month Ended December 31, 2009 (Subsequent to Emergence), and for the Eleven Months Ended November 30, 2009, and for the Year Ended December 31, 2008 (Prior to Emergence)

   
 
 

Report of Independent Registered Public Accounting Firm

   
F-206
 

Balance Sheets

    F-207  

Statements of Operations

    F-208  

Statements of Changes in Net Parent Equity (Deficit)

    F-209  

Statements of Cash Flows

    F-210  

Notes to Financial Statements

    F-211  

Unaudited Condensed Balance Sheets

    F-232  

Unaudited Condensed Statements of Operations

    F-233  

Unaudited Condensed Statements of Cash Flows

    F-234  

Notes to Unaudited Condensed Financial Statements

    F-235  

F-1


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Combined Financial Statements of the Businesses of the Osterman Associated Companies Contributed to NGL Energy Partners LP as of September 30, 2011 and 2010 and for Each of the Three Years in the Period Ended September 30, 2011

       

Report of Independent Certified Public Accountants

   
F-244
 

Combined Balance Sheets

    F-245  

Combined Statements of Operations and Changes in Equity of Combined Companies

    F-246  

Combined Statements of Cash Flows

    F-247  

Notes to Combined Financial Statements

    F-248  

Audited Combined Financial Statements of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, LLC, Toro Operating Company, Inc., and Striker Oilfield Services, LLC as of December 31, 2011 and for the Three Years Then Ended

   
 
 

Independent Auditors' Report

   
F-262
 

Combined Balance Sheets

    F-263  

Combined Statements of Income

    F-264  

Combined Statement of Changes in Members' and Stockholders' Equity

    F-265  

Combined Statements of Cash Flows

    F-266  

Notes to Combined Financial Statements

    F-267  

Unaudited Condensed Combined Financial Statements of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, LLC, Midstream Operations, LLC, Toro Operating Company, Inc., and Striker Oilfield Services, LLC as of September 30, 2012 and for the Nine Months Ended September 30, 2012 and 2011

   
 
 

Combined Balance Sheets

   
F-276
 

Unaudited Combined Statements of Income

    F-277  

Unaudited Combined Statement of Changes in Members' and Stockholders' Equity

    F-278  

Unaudited Combined Statements of Cash Flows

    F-279  

Notes to Unaudited Combined Financial Statements

    F-280  

Audited Consolidated Financial Statements of Oilfield Water Lines, LP as of December 31, 2012 and for the Period from Inception (August 6, 2012) through December 31, 2012

   
 
 

Independent Auditor's Report

   
F-289
 

Consolidated Balance Sheet

    F-290  

Consolidated Statement of Operations

    F-291  

Consolidated Statement of Changes in Partners' Capital

    F-292  

Consolidated Statement of Cash Flows

    F-293  

Notes to Consolidated Financial Statements

    F-294  

Audited Financial Statements of High Roller Wells Pearsall SWD No. 1, Ltd. for the Period from January 1, 2012 through August 28, 2012

   
 
 

Independent Auditor's Report

   
F-303
 

Statement of Operations

    F-304  

Statement of Partners' Capital

    F-305  

Statement of Cash Flows

    F-306  

Notes to Financial Statements

    F-307  

F-2


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Audited Financial Statements of High Roller Wells Karnes SWD No. 1, Ltd. for the Period from Inception (March 14, 2012) through December 4, 2012

       

Independent Auditor's Report

   
F-311
 

Statement of Operations and Partners' Capital

    F-312  

Statement of Cash Flows

    F-313  

Notes to Financial Statements

    F-314  

Audited Financial Statements of Lotus Oilfield Services, LLC for the period from January 1, 2012 through December 27, 2012

   
 
 

Independent Auditor's Report

   
F-318
 

Statement of Operations

    F-319  

Statement of Changes in Members' Equity

    F-320  

Statement of Cash Flows

    F-321  

Notes to Financial Statements

    F-322  

Unaudited Condensed Consolidated Financial Statements of Oilfield Water Lines, LP as of June 30, 2013 and for the Six Months Then Ended

   
 
 

Unaudited Condensed Consolidated Balance Sheets

   
F-326
 

Unaudited Condensed Consolidated Statement of Operations

    F-327  

Unaudited Condensed Consolidated Statement of Changes in Capital

    F-328  

Unaudited Condensed Consolidated Statement of Cash Flows

    F-329  

Notes to Unaudited Condensed Consolidated Financial Statements

    F-330  

Unaudited Condensed Financial Statements of High Roller Wells Pearsall SWD No. 1, Ltd. for the Six Months Ended June 30, 2012

   
 
 

Unaudited Condensed Statement of Operations

   
F-337
 

Unaudited Condensed Statement of Cash Flows

    F-338  

Notes to Unaudited Condensed Financial Statements

    F-339  

Unaudited Condensed Financial Statements of High Roller Wells Karnes SWD No. 1, Ltd. for the Period from Inception (March 14, 2012) through June 30, 2012

   
 
 

Unaudited Condensed Statement of Operations

   
F-343
 

Unaudited Condensed Statement of Cash Flows

    F-344  

Notes to Unaudited Condensed Financial Statements

    F-345  

Unaudited Condensed Financial Statements of Lotus Oilfield Services, LLC for the Six Months Ended June 30, 2012

   
 
 

Unaudited Condensed Statement of Operations

   
F-348
 

Unaudited Condensed Statement of Cash Flows

    F-349  

Notes to Unaudited Condensed Financial Statements

    F-350  

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Audited Combined Financial Statements of Gavilon Energy (The Energy Business Units of Gavilon, LLC) as of December 31, 2012 and 2011 and for the Three Years in the Period Ended December 31, 2012

       

Independent Auditors' Report

   
F-354
 

Combined Balance Sheets

    F-355  

Combined Statements of Operations

    F-356  

Combined Statements of Comprehensive Income (Loss)

    F-357  

Combined Statements of Equity

    F-358  

Combined Statements of Cash Flows

    F-359  

Notes to Combined Financial Statements

    F-360  

Unaudited Condensed Combined Financial Statements of Gavilon Energy (The Energy Business Units of Gavilon, LLC) as of September 30, 2013 and for the Nine Months Ended September 30, 2013 and 2012

   
 
 

Unaudited Condensed Combined Balance Sheets

   
F-376
 

Unaudited Condensed Combined Statements of Operations

    F-377  

Unaudited Condensed Combined Statements of Comprehensive Loss

    F-378  

Unaudited Condensed Combined Statement of Equity

    F-379  

Unaudited Condensed Combined Statements of Cash Flows

    F-380  

Notes to Unaudited Condensed Combined Financial Statements

    F-381  

Audited Combined Financial Statements of the Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP as of December 31, 2013 and 2012 and for the Two Years Then Ended

   
 
 

Independent Auditors' Report

   
F-395
 

Combined Balance Sheets

    F-396  

Combined Statements of Comprehensive Income (Loss)

    F-397  

Combined Statements of Equity

    F-398  

Combined Statements of Cash Flows

    F-399  

Notes to Combined Financial Statements

    F-400  

Unaudited Condensed Combined Financial Statements of the Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP as of June 30, 2014 and for the Six Months Ended June 30, 2014 and 2013

       

Unaudited Condensed Combined Balance Sheets

   
F-424
 

Unaudited Condensed Combined Statements of Comprehensive Loss

    F-425  

Unaudited Condensed Combined Statement of Equity

    F-426  

Unaudited Condensed Combined Statements of Cash Flows

    F-427  

Notes to Condensed Combined Financial Statements

    F-428  

F-4


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Report of Independent Registered Public Accounting Firm

Partners
NGL Energy Partners LP

        We have audited the accompanying consolidated balance sheets of NGL Energy Partners LP (a Delaware limited partnership) and subsidiaries (the "Partnership") as of March 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended March 31, 2014. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NGL Energy Partners LP and subsidiaries as of March 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2014 in conformity with accounting principles generally accepted in the United States of America.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of March 31, 2014, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated May 30, 2014 (not included herein) expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma
May 30, 2014 (except for Note 17, as to which the date is July 9, 2014)

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Report of Independent Registered Public Accounting Firm

Partners
NGL Energy Partners LP

        We have audited the internal control over financial reporting of NGL Energy Partners LP (a Delaware limited Partnership) and subsidiaries (the "Partnership") as of March 31, 2014, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting ("Management's Report"). Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit. Our audit of, and opinion on, the Partnership's internal control over financial reporting does not include the internal control over financial reporting of Gavilon, LLC ("Gavilon"), a wholly-owned subsidiary, whose financial statements reflect total assets and revenues constituting 31 and 30 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended March 31, 2014. As indicated in Management's Report, Gavilon was acquired during the year ended March 31, 2014. Management's assertion on the effectiveness of the Partnership's internal control over financial reporting excluded internal control over financial reporting of Gavilon.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of March 31, 2014, based on criteria established in the 1992 Internal Control—Integrated Framework issued by COSO.

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        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Partnership as of and for the year ended March 31, 2014, and our report dated May 30, 2014 expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma
May 30, 2014

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Balance Sheets

At March 31, 2014 and 2013

(U.S. Dollars in Thousands, except unit amounts)

 
  March 31,  
 
  2014   2013  
 
   
  (Note 2)
 

ASSETS

             

CURRENT ASSETS:

             

Cash and cash equivalents

  $ 10,440   $ 11,561  

Accounts receivable—trade, net of allowance for doubtful accounts of $2,822 and $1,760, respectively

    900,904     562,757  

Accounts receivable—affiliates

    7,445     22,883  

Inventories

    310,160     126,895  

Prepaid expenses and other current assets

    80,350     37,891  
           

Total current assets

    1,309,299     761,987  

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $109,564 and $50,127, respectively

   
829,346
   
526,437
 

GOODWILL

    1,107,006     555,220  

INTANGIBLE ASSETS, net of accumulated amortization of $116,728 and $44,155, respectively

    714,956     441,432  

INVESTMENTS IN UNCONSOLIDATED ENTITIES

    189,821      

OTHER NONCURRENT ASSETS

    16,795     6,542  
           

Total assets

  $ 4,167,223   $ 2,291,618  
           
           

LIABILITIES AND EQUITY

             

CURRENT LIABILITIES:

             

Accounts payable—trade

  $ 740,211   $ 536,055  

Accounts payable—affiliates

    76,846     6,900  

Accrued expenses and other payables

    141,690     85,606  

Advance payments received from customers

    29,965     22,372  

Current maturities of long-term debt

    7,080     8,626  
           

Total current liabilities

    995,792     659,559  

LONG-TERM DEBT, net of current maturities

   
1,629,834
   
740,436
 

OTHER NONCURRENT LIABILITIES

    9,744     2,205  

COMMITMENTS AND CONTINGENCIES

   
 
   
 
 

EQUITY, per accompanying statement:

   
 
   
 
 

General partner, representing a 0.1% interest, 79,420 and 53,676 notional units at March 31, 2014 and 2013, respectively

    (45,287 )   (50,497 )

Limited partners, representing a 99.9% interest—Common units, 73,421,309 and 47,703,313 units issued and outstanding at March 31, 2014 and 2013, respectively

    1,570,074     920,998  

Subordinated units, 5,919,346 units issued and outstanding at March 31, 2014 and 2013

    2,028     13,153  

Accumulated other comprehensive income (loss)

    (236 )   24  

Noncontrolling interests

    5,274     5,740  
           

Total equity

    1,531,853     889,418  
           

Total liabilities and equity

  $ 4,167,223   $ 2,291,618  
           
           

   

The accompanying notes are an integral part of these consolidated financial statements.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Statements of Operations

For the Years Ended March 31, 2014, 2013, and 2012

(U.S. Dollars in Thousands, except unit and per unit amounts)

 
  Year Ended March 31,  
 
  2014   2013   2012  

REVENUES:

                   

Crude oil logistics

  $ 4,558,545   $ 2,316,288   $  

Water solutions

    143,100     62,227      

Liquids

    2,650,425     1,604,746     1,111,139  

Retail propane

    551,815     430,273     199,334  

Refined products

    1,180,895          

Renewables

    176,781          

Other

    437,713     4,233      
               

Total Revenues

    9,699,274     4,417,767     1,310,473  
               

COST OF SALES:

                   

Crude oil logistics

    4,477,397     2,244,647      

Water solutions

    11,738     5,611      

Liquids

    2,518,099     1,530,459     1,086,881  

Retail propane

    354,676     258,393     130,142  

Refined products

    1,172,754          

Renewables

    171,422          

Other

    426,613          
               

Total Cost of Sales

    9,132,699     4,039,110     1,217,023  
               

OPERATING COSTS AND EXPENSES:

                   

Operating

    259,396     169,799     47,300  

General and administrative

    79,860     52,698     16,009  

Depreciation and amortization

    120,754     68,853     15,111  
               

Operating Income

    106,565     87,307     15,030  

OTHER INCOME (EXPENSE):

   
 
   
 
   
 
 

Earnings of unconsolidated entities

    1,898          

Interest expense

    (58,854 )   (32,994 )   (7,620 )

Loss on early extinguishment of debt

        (5,769 )    

Other, net

    86     1,521     1,055  
               

Income Before Income Taxes

    49,695     50,065     8,465  

INCOME TAX PROVISION

   
(937

)
 
(1,875

)
 
(601

)
               

Net Income

    48,758     48,190     7,864  

NET INCOME ALLOCATED TO GENERAL PARTNER

   
(14,148

)
 
(2,917

)
 
(8

)

NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS

   
(1,103

)
 
(250

)
 
12
 
               

NET INCOME ALLOCATED TO LIMITED PARTNERS

  $ 33,507   $ 45,023   $ 7,868  
               
               

BASIC AND DILUTED INCOME PER COMMON UNIT

  $ 0.51   $ 0.96   $ 0.32  
               
               

BASIC AND DILUTED INCOME PER SUBORDINATED UNIT

  $ 0.32   $ 0.93   $ 0.58  
               
               

BASIC AND DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING:

                   

Common units

    61,970,471     41,353,574     15,169,983  
               
               

Subordinated units

    5,919,346     5,919,346     5,175,384  
               
               

   

The accompanying notes are an integral part of these consolidated financial statements.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income

For the Years Ended March 31, 2014, 2013, and 2012

(U.S. Dollars in Thousands)

 
  Year Ended March 31,  
 
  2014   2013   2012  

Net income

  $ 48,758   $ 48,190   $ 7,864  

Other comprehensive loss, net of tax

    (260 )   (7 )   (25 )
               

Comprehensive income

  $ 48,498   $ 48,183   $ 7,839  
               
               

   

The accompanying notes are an integral part of these consolidated financial statements.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Statements of Changes in Equity

For the Years Ended March 31, 2014, 2013, and 2012

(U.S. Dollars in Thousands, except unit and share amounts)

 
   
  Limited Partners    
   
   
 
 
   
  Accumulated
Other
Comprehensive
Income
   
   
 
 
  General
Partner
  Common
Units
  Amount   Subordinated
Units
  Amount   Noncontrolling
Interests
  Total
Equity
 

BALANCES, MARCH 31, 2011

  $ 72     10,933,568   $ 47,225       $   $ 56   $   $ 47,353  

Distribution to partners prior to initial public offering

    (4 )       (3,846 )                   (3,850 )

Conversion of common units to subordinated units

        (5,919,346 )   (23,485 )   5,919,346     23,485              

Sale of units in public offering, net

        4,025,000     75,289                     75,289  

Repurchase of common units

        (175,000 )   (3,418 )                   (3,418 )

Units issued in business combinations, net of issuance costs

        14,432,031     296,500                     296,500  

Contributions

    386                         440     826  

Net income (loss)

    8         6,472         1,396         (12 )   7,864  

Distribution to partners subsequent to initial public offering

    (20 )       (10,133 )       (5,057 )           (15,210 )

Other comprehensive loss

                        (25 )       (25 )
                                   

BALANCES, MARCH 31, 2012

    442     23,296,253     384,604     5,919,346     19,824     31     428     405,329  

Distributions

    (1,778 )       (59,841 )       (9,989 )       (74 )   (71,682 )

Contributions

    510                         403     913  

Units issued in business combinations, net of issuance costs

    (52,588 )   24,250,258     550,873                 4,733     503,018  

Equity issued pursuant to incentive compensation plan             

        156,802     3,657                     3,657  

Net income

    2,917         41,705         3,318         250     48,190  

Other comprehensive loss

                        (7 )       (7 )
                                   

BALANCES, MARCH 31, 2013

    (50,497 )   47,703,313     920,998     5,919,346     13,153     24     5,740     889,418  

Distributions

    (9,703 )       (123,467 )       (11,920 )       (840 )   (145,930 )

Contributions

    765                         2,060     2,825  

Units issued in business combinations, net of issuance costs

        2,860,879     80,591                     80,591  

Sales of units, net of issuance costs

        22,560,848     650,155                     650,155  

Equity issued pursuant to incentive compensation plan             

        296,269     9,085                     9,085  

Disposal of noncontrolling interest

                            (2,789 )   (2,789 )

Net income

    14,148         32,712         795         1,103     48,758  

Other comprehensive loss

                        (260 )       (260 )
                                   

BALANCES, MARCH 31, 2014

  $ (45,287 )   73,421,309   $ 1,570,074     5,919,346   $ 2,028   $ (236 ) $ 5,274   $ 1,531,853  
                                   
                                   

   

The accompanying notes are an integral part of these consolidated financial statements.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Statements of Cash Flows

For the Years Ended March 31, 2014, 2013, and 2012

(U.S. Dollars in Thousands)

 
  Year Ended March 31,  
 
  2014   2013   2012  

OPERATING ACTIVITIES:

                   

Net income

  $ 48,758   $ 48,190   $ 7,864  

Adjustments to reconcile net income to net cash provided by operating activities:

                   

Depreciation and amortization, including debt issuance cost amortization

    132,653     77,513     17,188  

Loss on early extinguishment of debt

        5,769      

Non-cash equity-based compensation expense

    14,054     8,670      

Loss (gain) on disposal or impairment of assets

    3,597     187     (71 )

Provision for doubtful accounts

    2,172     1,315     1,049  

Commodity derivative (gain) loss

    43,655     4,376     (5,974 )

Earnings of unconsolidated entities

    (1,898 )        

Other

    312     375     403  

Changes in operating assets and liabilities, exclusive of acquisitions:

                   

Accounts receivable—trade

    21,388     2,562     (20,179 )

Accounts receivable—affiliates

    18,002     (12,877 )   193  

Inventories

    (73,321 )   18,433     30,268  

Prepaid expenses and other current assets

    18,900     22,585     14,344  

Accounts payable—trade

    (146,152 )   (16,913 )   35,747  

Accounts payable—affiliates

    67,361     (6,813 )   4,549  

Accrued expenses and other payables

    (61,171 )   (9,689 )   366  

Advance payments received from customers

    (3,074 )   (11,049 )   4,582  
               

Net cash provided by operating activities

    85,236     132,634     90,329  
               

INVESTING ACTIVITIES:

                   

Purchases of long-lived assets

    (165,148 )   (72,475 )   (7,544 )

Acquisitions of businesses, including acquired working capital, net of cash acquired

    (1,268,810 )   (490,805 )   (297,401 )

Cash flows from commodity derivatives

    (35,956 )   11,579     6,464  

Proceeds from sales of assets

    24,660     5,080     1,238  

Investments in unconsolidated entities

    (11,515 )        

Distributions of capital from unconsolidated entities

    1,591          

Other

    (195 )       346  
               

Net cash used in investing activities

    (1,455,373 )   (546,621 )   (296,897 )
               

FINANCING ACTIVITIES:

                   

Proceeds from borrowings under revolving credit facilities

    2,545,500     1,227,975     478,900  

Payments on revolving credit facilities

    (2,101,000 )   (964,475 )   (329,900 )

Issuances of notes

    450,000     250,000      

Proceeds from borrowings on other long-term debt

    880     653      

Payments on other long-term debt

    (8,819 )   (4,837 )   (1,278 )

Debt issuance costs

    (24,595 )   (20,189 )   (2,380 )

Contributions

    2,825     913     440  

Distributions

    (145,930 )   (71,682 )   (19,060 )

Proceeds from sale of common units, net of offering costs

    650,155     (642 )   74,759  

Repurchase of common units

            (3,418 )
               

Net cash provided by financing activities

    1,369,016     417,716     198,063  
               

Net increase (decrease) in cash and cash equivalents

    (1,121 )   3,729     (8,505 )

Cash and cash equivalents, beginning of period

    11,561     7,832     16,337  
               

Cash and cash equivalents, end of period

  $ 10,440   $ 11,561   $ 7,832  
               
               

   

The accompanying notes are an integral part of these consolidated financial statements.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 1—Nature of Operations and Organization

        NGL Energy Partners LP ("we," "us," "our," or the "Partnership") is a Delaware limited partnership formed in September 2010 by several investors ("IEP Parties"). NGL Energy Holdings LLC serves as our general partner. At March 31, 2014, our operations include:

        We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products in back-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business, which purchases ethanol primarily at production facilities and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders. These businesses were acquired in our December 2013 acquisition of Gavilon, LLC ("Gavilon Energy").

Initial Public Offering

        On May 17, 2011, we completed our initial public offering ("IPO"). We sold a total of 4,025,000 common units in our IPO at $21.00 per unit. Our proceeds from the sale of 3,850,000 common units of $71.9 million, net of total offering costs of $9.0 million, were used to repay advances under our acquisition credit facility and for general partnership purposes. Proceeds from the sale of 175,000 common units ($3.4 million) from the underwriters' exercise of their option to purchase additional common units from us were used to redeem 175,000 of the common units outstanding prior to our IPO. Upon the completion of our IPO and the underwriters' exercise in full of their option to purchase additional common units from us and the redemption, we had outstanding 8,864,222 common units,

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 1—Nature of Operations and Organization (Continued)

5,919,346 subordinated units, a 0.1% general partner interest, and incentive distribution rights ("IDRs").

Acquisitions Subsequent to Initial Public Offering

        Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, including the following, among others:

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 1—Nature of Operations and Organization (Continued)

Note 2—Significant Accounting Policies

Basis of Presentation

        Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The accompanying consolidated financial statements include the accounts of the Partnership and its controlled subsidiaries. All significant intercompany transactions and account balances have been eliminated in consolidation.

        We have made certain reclassifications to the prior period financial statements to conform with classification methods used in fiscal 2014. These reclassifications had no impact on previously-reported amounts of equity or net income. In addition, certain balances at March 31, 2013 were adjusted to reflect the final acquisition accounting for certain business combinations.

Use of Estimates

        The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amount of revenues and expenses during the period.

        Critical estimates we make in the preparation of our consolidated financial statements include determining the fair value of assets and liabilities acquired in business combinations; the collectability of accounts receivable; the recoverability of inventories; useful lives and recoverability of property, plant and equipment and amortizable intangible assets; the impairment of goodwill; the fair value of derivative financial investments; and accruals for various commitments and contingencies, among others. Although we believe these estimates are reasonable, actual results could differ from those estimates.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

Fair Value Measurements

        We apply fair value measurements to certain assets and liabilities, principally our commodity derivative instruments and assets and liabilities acquired in business combinations. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

        We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

        The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

Derivative Financial Instruments

        We record our derivative financial instrument contracts at fair value in the consolidated balance sheets, with changes in the fair value of our commodity derivative instruments included in our consolidated statements of operations in cost of sales. Contracts that qualify for the normal purchase or sale exemption and are designated as such are not accounted for as derivatives at market value and, accordingly, are recorded when the delivery occurs.

        We have not designated any financial instruments as hedges for accounting purposes. All mark-to-market gains and losses on commodity derivative instruments that do not qualify as normal purchases or sales, whether cash transactions or non-cash mark-to-market adjustments, are reported within cost of sales in the consolidated statements of operations, regardless of whether the contract is physically or financially settled.

        We utilize various commodity derivative financial instrument contracts to help reduce our exposure to variability in future commodity prices. We do not enter such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in market prices, newly originated transactions, and the timing of the settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipated market movements. Inherent in the resulting contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from non-performance by suppliers, customers, or financial counterparties to a contract. We take an active role in managing and controlling market and credit risk and have established control procedures that we review on an ongoing basis. We monitor market risk through a variety of techniques and attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures.

Revenue Recognition

        We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. We record terminaling, storage, and service revenues at the time the service is performed, and we record tank and other rentals over the term of the lease. Revenues for the wastewater disposal business are recognized upon receipt of the wastewater at our disposal facilities.

        We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. Amounts billed to customers for shipping and handling costs are included in revenues in the consolidated statements of operations.

        We enter into certain contracts whereby we agree to purchase product from a counterparty and to sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into concurrently and are entered into in contemplation of each other, we record the revenues for these transactions net of cost of sales.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

Cost of Sales

        We include in cost of sales all costs we incur to acquire products, including the costs of purchasing, terminaling, and transporting inventory prior to delivery to our customers. Cost of sales does not include any depreciation of our property, plant and equipment. Cost of sales does include amortization of certain contract-based intangible assets of $6.2 million, $5.3 million, and $0.8 million during the years ended March 31, 2014, 2013, and 2012, respectively.

Depreciation and Amortization

        Depreciation and amortization in the consolidated statements of operations includes all depreciation of our property, plant and equipment and amortization of intangible assets other than debt issuance costs, for which the amortization is recorded to interest expense, and certain contract-based intangible assets, for which the amortization is recorded to cost of sales.

Cash and Cash Equivalents

        Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of three months or less at the date of purchase. At times, certain account balances may exceed federally insured limits.

        Supplemental cash flow information is as follows:

 
  Year Ended March 31,  
 
  2014   2013   2012  
 
  (in thousands)
 

Interest paid, exclusive of debt issuance costs and letter of credit fees

  $ 31,827   $ 27,384   $ 4,966  
               
               

Income taxes paid

  $ 1,639   $ 1,027   $ 430  
               
               

        Cash flows from commodity derivative instruments are classified as cash flows from investing activities in the consolidated statements of cash flows.

Accounts Receivable and Concentration of Credit Risk

        We operate in the United States and Canada. We grant unsecured credit to customers under normal industry standards and terms, and have established policies and procedures that allow for an evaluation of each customer's creditworthiness as well as general economic conditions. The allowance for doubtful accounts is based on our assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes. Accounts receivable are considered past due or delinquent based on contractual terms. We write off accounts receivable against the allowance for doubtful accounts when collection efforts have been exhausted.

        We execute netting agreements with certain customers to mitigate our credit risk. Receivables and payables are reflected at a net balance to the extent a netting agreement is in place and we intend to settle on a net basis.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

        Our accounts receivable consist of the following:

 
  March 31, 2014   March 31, 2013  
Segment
  Gross
Receivable
  Allowance for
Doubtful
Accounts
  Gross
Receivable
(Note 2)
  Allowance for
Doubtful
Accounts
 
 
  (in thousands)
 

Crude oil logistics

  $ 411,090   $ 105   $ 360,589   $ 11  

Water solutions

    25,700     405     9,618     29  

Liquids

    192,529     617     144,267     76  

Retail propane

    75,606     1,667     49,233     1,644  

Refined products

    105,670              

Renewables

    54,466              

Other

    38,665     28     810      
                   

  $ 903,726   $ 2,822   $ 564,517   $ 1,760  
                   
                   

        Changes in the allowance for doubtful accounts are as follows:

 
  Year Ended March 31,  
 
  2014   2013   2012  
 
  (in thousands)
 

Allowance for doubtful accounts, beginning of period

  $ 1,760   $ 818   $ 161  

Provision for doubtful accounts

    2,172     1,315     1,049  

Write off of uncollectible accounts

    (1,110 )   (373 )   (392 )
               

Allowance for doubtful accounts, end of period

  $ 2,822   $ 1,760   $ 818  
               
               

        For the year ended March 31, 2014, sales of crude oil and natural gas liquids to our largest customer represented 10% of our consolidated total revenues. For the year ended March 31, 2013, sales of crude oil and natural gas liquids to our largest customer represented 10% of our consolidated total revenues. At March 31, 2013, one customer of our crude oil logistics segment represented 10% of our consolidated accounts receivable balance.

Inventories

        We value our inventory at the lower of cost or market, with cost determined using either the weighted average cost or the first in, first out (FIFO) methods, including the cost of transportation. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business for sale in the retail markets.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

        Inventories consist of the following:

 
  March 31,  
 
  2014   2013  
 
  (in thousands)
 

Crude oil

  $ 156,473   $ 46,156  

Natural gas liquids—

             

Propane

    85,159     45,428  

Butane and other

    19,051     24,090  

Refined products

    23,209      

Renewables

    11,778      

Other

    14,490     11,221  
           

  $ 310,160   $ 126,895  
           
           

Investments in Unconsolidated Entities

        As part of the December 2013 acquisition of Gavilon Energy, we acquired a 50% interest in Glass Mountain and an 11% interest in a limited liability company that owns an ethanol production facility. We account for these investments under the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on our consolidated balance sheet; instead, our ownership interests are reported within "Investments in Unconsolidated Entities" on our consolidated balance sheet. We record our share of any income or loss generated by these entities as an increase to our equity method investments, and record any distributions we receive from these entities as reductions to our equity method investments.

Accrued Expenses and Other Payables

        Accrued expenses and other payables consist of the following:

 
  March 31,  
 
  2014   2013
(Note 4)
 
 
  (in thousands)
 

Accrued compensation and benefits

  $ 45,006   $ 27,252  

Derivative liabilities

    42,214     12,701  

Income and other tax liabilities

    13,421     22,659  

Product exchange liabilities

    3,719     6,741  

Other

    37,330     16,253  
           

  $ 141,690   $ 85,606  
           
           

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

Property, Plant and Equipment

        We record property, plant and equipment at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and maintenance and repairs are expensed as incurred. As we dispose of assets, we remove the cost and related accumulated depreciation from the accounts, and any resulting gain or loss is included in other income. We compute depreciation expense using the straight-line method over the estimated useful lives of the assets (see Note 5).

        We evaluate the carrying value of our property, plant and equipment for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is lower than its carrying value. In that event, we recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group.

Intangible Assets

        Our intangible assets include contracts and arrangements acquired in business combinations, including lease agreements, customer relationships, covenants not to compete, and trade names. In addition, we capitalize certain debt issuance costs incurred in our long-term debt arrangements. We amortize our intangible assets on a straight-line basis over the assets' estimated useful lives (see Note 7). We amortize debt issuance costs over the terms of the related debt on a method that approximates the effective interest method.

        We evaluate the carrying value of our amortizable intangible assets for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is lower than its carrying value. In that event, we recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group. When we cease to use an acquired trade name, we test the trade name for impairment using the "relief from royalty" method and we begin amortizing the trade name over its estimated useful life as a defensive asset.

Goodwill

        Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Business combinations are accounted for using the "acquisition method" (see Note 4). We expect that substantially all of our goodwill at March 31, 2014 is deductible for income tax purposes.

        Goodwill and intangible assets determined to have an indefinite useful life are not amortized, but instead are evaluated for impairment periodically. We evaluate goodwill and indefinite-lived intangible assets for impairment annually, or more often if events or circumstances indicate that the assets might be impaired. We perform the annual evaluation at January 1 of each year.

        To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting unit exceeds its carrying amount. If we conclude that it is

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

more likely than not that the fair value of a reporting unit exceeds its carrying amount, we perform the following two-step goodwill impairment test:

        Estimates and assumptions used to perform the impairment evaluation are inherently uncertain and can significantly affect the outcome of the analysis. The estimates and assumptions we used in the annual assessment for impairment of goodwill included market participant considerations and future forecasted operating results. Changes in operating results and other assumptions could materially affect these estimates. Based on our assessment of qualitative factors, we determined that the two-step impairment test was not required. Accordingly, we did not record any goodwill impairments during the years ended March 31, 2014, 2013, and 2012.

Product Exchanges

        Quantities of products receivable or returnable under exchange agreements are reported within prepaid expenses and other current assets or within accrued expenses and other payables on the consolidated balance sheets. We estimate the value of product exchange assets and liabilities based on the weighted-average cost basis of the inventory we have delivered or will deliver on the exchange, plus or minus location differentials.

Advance Payments Received from Customers

        We record customer advances on product purchases as a liability on the consolidated balance sheets.

Noncontrolling Interests

        We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our consolidated statements of operations represents the other owners' share of the net income (loss) of these entities.

Water Facility Development Agreement

        In connection with one of our business combinations, we entered into a development agreement whereby we may acquire additional water disposal facilities in Texas. Under this agreement, the other party (the "Developer") may develop facilities in a designated area. We then have the option to operate the facility for a period of up to 90 days, during which time we may elect to purchase the

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

facility. If we elect to purchase the facility, the Developer may choose one of two options specified in the agreement for the calculation of the purchase price.

        During the period between which we have begun operating the facility and we have decided whether to purchase the facility, we are entitled to a fee for operating the facility, which is forfeitable if we elect not to purchase the facility. We recognize revenue for these operator fees once they cease to be forfeitable. When we elect to purchase a facility, we account for the transaction as a business combination.

Business Combination Measurement Period

        We record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Pursuant to GAAP, an entity is allowed a reasonable period of time to obtain the information necessary to identify and measure the value of the assets acquired and liabilities assumed in a business combination. As described in Note 4, certain of our acquisitions during the year ended March 31, 2014 are still within this measurement period, and as a result, the acquisition-date fair values we have recorded for the acquired assets and assumed liabilities are subject to change.

        Also as described in Note 4, we made certain adjustments during the year ended March 31, 2014 to our estimates of the acquisition date fair values of assets acquired and liabilities assumed in business combinations that occurred during the year ended March 31, 2013. We retrospectively adjusted the March 31, 2013 consolidated balance sheet for these adjustments. Due to the immateriality of these adjustments, we did not retrospectively adjust the consolidated statement of operations for the year ended March 31, 2013 for these measurement period adjustments.

Discontinued Operations

        In April 2014, the Financial Accounting Standards Board issued an Accounting Standards Update that changes the criteria for reporting discontinued operations. Under the new standard, a disposal of part of an entity is not classified as a discontinued operation unless the disposal represents a strategic shift that will have a major effect on an entity's operations and financial results. We adopted the new standard during the fiscal year ended March 31, 2014.

        As described in Note 14, during the year ended March 31, 2014, we sold our compressor leasing business and wound down our natural gas marketing business. These actions do not represent a strategic shift that had a major effect on our operations, and do not meet the criteria under the new accounting standard for these businesses to be reported as discontinued operations.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 3—Earnings per Unit

        Our earnings per common and subordinated unit were computed as follows:

 
  Year Ended March 31,  
 
  2014   2013   2012  
 
  (in thousands, except unit and per unit amounts)
 

Income attributable to parent equity

  $ 47,655   $ 47,940   $ 7,876  

Income allocated to general partner(1)

    (14,148 )   (2,917 )   (8 )
               

Income attributable to limited partners

  $ 33,507   $ 45,023   $ 7,868  
               
               

Income allocated to:

                   

Common unitholders

  $ 31,614   $ 39,517   $ 4,859  
               
               

Subordinated unitholders

  $ 1,893   $ 5,506   $ 3,009  
               
               

Weighted average common units outstanding

    61,970,471     41,353,574     15,169,983  
               
               

Weighted average subordinated units outstanding

    5,919,346     5,919,346     5,175,384  
               
               

Income per common unit—basic and diluted

  $ 0.51   $ 0.96   $ 0.32  
               
               

Income per subordinated unit—basic and diluted

  $ 0.32   $ 0.93   $ 0.58  
               
               

(1)
The income allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights ("IDRs"), which are described in Note 11.

        The restricted units described in Note 11 were antidilutive for the years ended March 31, 2014, 2013, and 2012.

Note 4—Acquisitions

Year Ended March 31, 2014

Gavilon Energy

        On December 2, 2013, we completed a business combination in which we acquired Gavilon Energy. We paid $832.4 million of cash, net of cash acquired, in exchange for these assets and operations. The acquisition agreement also contemplates a post-closing adjustment to the purchase price for certain working capital items. We incurred and charged to general and administrative expense $5.3 million of costs during the year ended March 31, 2014 related to the acquisition of Gavilon Energy.

        The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas, and Louisiana and a 50% interest in Glass Mountain, which owns a crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma. This pipeline became operational in February 2014. The

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids.

        We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in the acquisition of Gavilon Energy. The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending September 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable—trade

  $ 349,529  

Accounts receivable—affiliates

    2,564  

Inventories

    107,430  

Prepaid expenses and other current assets

    68,322  

Property, plant and equipment:

       

Crude oil tanks and related equipment (3 - 40 years)

    77,429  

Vehicles (3 years)

    791  

Information technology equipment (3 - 7 years)

    4,046  

Buildings and leasehold improvements (3 - 40 years)

    7,716  

Land

    6,427  

Linefill and tank bottoms

    15,230  

Other (7 years)

    170  

Construction in process

    7,190  

Goodwill

    359,169  

Intangible assets:

       

Customer relationships (10 - 20 years)

    101,600  

Lease agreements (1 - 5 years)

    8,700  

Investments in unconsolidated entities

    178,000  

Other noncurrent assets

    9,918  

Accounts payable—trade

    (342,792 )

Accounts payable—affiliates

    (2,585 )

Accrued expenses and other payables

    (70,999 )

Advance payments received from customers

    (10,667 )

Other noncurrent liabilities

    (44,740 )
       

Fair value of net assets acquired

  $ 832,448  
       
       

        Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entity and the Partnership, the opportunity to use the acquired business as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

        Our preliminary estimate of the fair value of investments in unconsolidated subsidiaries exceeds our share of the historical net book value of these subsidiaries' net assets by approximately $70 million. This difference relates primarily to goodwill and customer relationships.

        The acquisition method of accounting requires that executory contracts that are at unfavorable terms relative to current market conditions at the acquisition date be recorded as assets or liabilities in the acquisition accounting. Since certain crude oil storage lease commitments were at unfavorable terms relative to current market conditions, we recorded a liability of $12.9 million related to these lease commitments in the acquisition accounting, and we amortized $2.9 million of this balance through cost of sales during the period from the acquisition date through March 31, 2014. We will amortize the remainder of this liability over the term of the leases. The future amortization of this liability is shown below (in thousands):

Year Ending March 31,
   
 

2015

  $ 6,500  

2016

    3,260  

2017

    300  

        As described in Note 14, on March 31, 2014, we assigned all of the storage and transportation contracts of the natural gas marketing business to a third party. Since these contracts were at unfavorable terms relative to current market conditions, we paid $44.8 million to assign these contracts. We recorded a liability of $50.8 million related to these storage and transportation contracts in the acquisition accounting, and we amortized $6.0 million of this balance through cost of sales during the period from the acquisition date through the date we assigned the contracts.

        We recorded $3.2 million of employee severance expense during the year ended March 31, 2014 as a result of personnel changes subsequent to the acquisition of Gavilon Energy. In addition, certain personnel who were employees of Gavilon Energy are entitled to a bonus, half of which was payable upon successful completion of the business combination and the remainder of which is payable in December 2014. We are recording this as compensation expense over the vesting period. We recorded expense of $5.0 million during the year ended March 31, 2014 related to these bonuses, and we expect to record an additional expense of $6.6 million during the year ending March 31, 2015.

        The operations of Gavilon Energy have been included in our consolidated statement of operations since Gavilon Energy was acquired on December 2, 2013. Our consolidated statement of operations for the year ended March 31, 2014 includes revenues of $2.9 billion and operating income of $11.0 million that were generated by the operations of Gavilon Energy.

Oilfield Water Lines, LP

        On August 2, 2013, we completed a business combination with entities affiliated with OWL, whereby we acquired water disposal and transportation assets in Texas. We issued 2,463,287 common units, valued at $68.6 million, and paid $167.7 million of cash, net of cash acquired, in exchange for OWL. The acquisition agreements included a provision whereby the purchase price could have been increased if certain performance targets were achieved in the six months following the acquisition. These performance targets were not achieved, and therefore no increase to the purchase price was

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

warranted. The acquisition agreements also contemplate a post-closing payment for certain working capital items. We incurred and charged to general and administrative expense $0.8 million of costs related to the OWL acquisition during the year ended March 31, 2014.

        We have completed the process of identifying and determining the fair value of the long-lived assets acquired in the acquisition of OWL. We have not yet finalized any post-closing payment for certain working capital items, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable—trade

  $ 7,268  

Inventories

    154  

Prepaid expenses and other current assets

    402  

Property, plant and equipment:

       

Land

    710  

Water treatment facilities and equipment (3 - 30 years)

    23,173  

Vehicles (5 - 10 years)

    8,157  

Buildings and leasehold improvements (7 - 30 years)

    2,198  

Other (3 - 5 years)

    53  

Intangible assets:

       

Customer relationships (10 years)

    110,000  

Non-compete agreements (2.5 years)

    2,000  

Goodwill

    89,699  

Accounts payable—trade

    (6,469 )

Accrued expenses and other payables

    (992 )

Other noncurrent liabilities

    (64 )
       

Fair value of net assets acquired

  $ 236,289  
       
       

        Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired

  $ 167,732  

Value of common units issued

    68,557  
       

Total consideration paid

  $ 236,289  
       
       

        The customer relationships were valued using a variation of the income approach known as the excess earnings method. This methodology consists of deriving relevant cash flows to the underlying asset, and then deducting appropriate returns for other assets contributing to the generation of the relevant cash flows. This valuation methodology requires estimates of customer retention, which were based on our understanding of the level of competition in the region in which the assets operate. Our estimates of customer retention are also relevant to the determination of the estimated useful lives of the assets.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

        Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

        The operations of OWL have been included in our consolidated statement of operations since OWL was acquired on August 2, 2013. Our consolidated statement of operations for the year ended March 31, 2014 includes revenues of $26.2 million and operating income of $0.9 million that was generated by the operations of OWL.

Other Water Solutions Acquisitions

        During the year ended March 31, 2014, we completed four separate acquisitions of businesses to expand our water solutions operations in Texas. On a combined basis, we issued 222,381 common units, valued at $6.8 million, and paid $178.9 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. Our consolidated statement of operations for the year ended March 31, 2014 includes revenues of $20.6 million and operating income of $7.1 million that was generated by the operations of these acquisitions. We incurred and charged to general and administrative expense $0.4 million of costs related to these acquisitions during the year ended March 31, 2014.

        We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these four business combinations. The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending September 30, 2014. We have

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable—trade

  $ 2,391  

Inventories

    390  

Prepaid expenses and other current assets

    61  

Property, plant and equipment:

       

Land

    419  

Vehicles (5 - 10 years)

    90  

Water treatment facilities and equipment (3 - 30 years)

    24,933  

Buildings and leasehold improvements (7 - 30 years)

    3,036  

Other (3 - 5 years)

    13  

Intangible assets:

       

Customer relationships (8 - 10 years)

    72,000  

Trade names (indefinite life)

    3,325  

Non-compete agreements (3 years)

    260  

Water facility development agreement (5 years)

    14,000  

Water facility option agreement

    2,500  

Goodwill

    63,031  

Accounts payable—trade

    (382 )

Accrued expenses and other payables

    (300 )

Other noncurrent liabilities

    (114 )
       

Fair value of net assets acquired

  $ 185,653  
       
       

        Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired

  $ 178,867  

Value of common units issued

    6,786  
       

Total consideration paid

  $ 185,653  
       
       

        Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

        As part of one of these business combinations, we entered into an option agreement with the seller of the business whereby we had the option to purchase a salt water disposal facility that was under construction. We recorded an intangible asset of $2.5 million at the acquisition date related to this option agreement. On March 1, 2014, we purchased the saltwater disposal facility for additional cash consideration of $3.7 million. The assets associated with this facility are included in the data in the table above.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

        As part of one of these business combinations, we entered into a development agreement that provides us a first right of refusal to purchase disposal facilities that may be developed by the seller within a defined area in the Eagle Ford Basin through June 2018. On March 1, 2014, we purchased our first disposal facility pursuant to the development agreement for $21.0 million. The assets associated with this facility are included in the data in the table above. In addition, we have exercised our option to operate, for evaluation purposes, three additional disposal facilities developed by the seller. Pending the results of our evaluation, we have the right to purchase any or all of these facilities within the 90-day evaluation period.

Crude Oil Logistics Acquisitions

        During the year ended March 31, 2014, we completed two separate acquisitions of businesses to expand our crude oil logistics business in Texas and Oklahoma. On a combined basis, we issued 175,211 common units, valued at $5.3 million, and paid $67.8 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. The agreement for the acquisition of one of these businesses contemplates a post-closing payment for certain working capital items. We incurred and charged to general and administrative expense during the year ended March 31, 2014 $0.1 million of costs related to these acquisitions.

        We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these two business combinations. The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable—trade

  $ 1,235  

Inventories

    1,021  

Prepaid expenses and other current assets

    54  

Property, plant and equipment:

       

Vehicles (5 - 10 years)

    2,977  

Buildings and leasehold improvements (5 - 30 years)

    280  

Crude oil tanks and related equipment (2 - 30 years)

    3,462  

Barges and towboats (20 years)

    20,065  

Other (3 - 5 years)

    53  

Intangible assets:

       

Customer relationships (3 years)

    6,300  

Non-compete agreements (3 years)

    35  

Trade names (indefinite life)

    530  

Goodwill

    37,867  

Accounts payable—trade

    (665 )

Accrued expenses and other payables

    (124 )
       

Fair value of net assets acquired

  $ 73,090  
       
       

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

        Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired

  $ 67,842  

Value of common units issued

    5,248  
       

Total consideration paid

  $ 73,090  
       
       

        Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Retail Propane and Liquids Acquisitions

        During the year ended March 31, 2014, we completed four acquisitions of retail propane businesses and the acquisition of four natural gas liquids terminals. On a combined basis, we paid $21.9 million of cash to acquire these assets and operations. The agreements for certain of these acquisitions contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in certain of these business combinations, and as a result the estimates of fair value reflected at March 31, 2014 are subject to change.

Year Ended March 31, 2013

High Sierra Combination

        On June 19, 2012, we completed a business combination with High Sierra, whereby we acquired all of the ownership interests in High Sierra. We paid $91.8 million of cash, net of $5.0 million of cash acquired, and issued 18,018,468 common units to acquire High Sierra Energy, LP. These common units were valued at $406.8 million using the closing price of our common units on the New York Stock Exchange (the "NYSE") on the merger date. We also paid $97.4 million of High Sierra Energy, LP's long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our general partner. We recorded the value of the 2,685,042 common units issued to our general partner at $8.0 million, which represents an estimate, in accordance with GAAP, of the fair value of the equity issued by our general partner to the former owners of High Sierra's general partner. In accordance with the GAAP fair value model, this fair value was estimated based on assumptions of future distributions and a discount rate that a hypothetical buyer might use. Under this model, the potential for distribution growth resulting from the prospect of future acquisitions and capital expansion projects would not be considered in the fair value calculation. The difference between the estimated fair value of the general partner interests issued by our general partner of $8.0 million, calculated as described above, and the fair value of the common units issued to our general partner of $60.6 million, as calculated using the closing price of the common units on the NYSE, is reported as a reduction to equity. We incurred and charged to general and

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

administrative expense during the years ended March 31, 2013 $3.7 million of costs related to the High Sierra transaction. We also incurred or accrued costs of $0.6 million related to the equity issuance that we charged to equity.

        The fair values of the assets acquired and liabilities assumed in our acquisition of High Sierra are summarized below (in thousands):

Accounts receivable—trade

  $ 395,311  

Accounts receivable—affiliates

    7,724  

Inventories

    43,575  

Derivative assets

    10,646  

Forward purchase and sale contracts

    34,717  

Prepaid expenses and other current assets

    11,131  

Property, plant and equipment:

       

Land

    5,723  

Vehicles (5 - 10 years)

    22,507  

Water treatment facilities and equipment (3 - 30 years)

    64,057  

Crude oil tanks and related equipment (2 - 15 years)

    17,851  

Buildings and leasehold improvements (5 - 30 years)

    19,145  

Information technology equipment (3 years)

    5,541  

Other (2 - 30 years)

    11,010  

Construction in progress

    9,621  

Intangible assets:

       

Customer relationships (5 - 17 years)

    245,000  

Lease contracts (1 - 10 years)

    12,400  

Trade names (indefinite)

    13,000  

Goodwill

    220,884  

Accounts payable—trade

    (417,369 )

Accounts payable—affiliates

    (9,014 )

Advance payments received from customers

    (1,237 )

Accrued expenses and other payables

    (35,611 )

Derivative liabilities

    (5,726 )

Forward purchase and sale contracts

    (18,680 )

Long-term debt

    (2,537 )

Other noncurrent liabilities

    (3,224 )

Noncontrolling interest in consolidated subsidiary

    (2,400 )
       

Consideration paid, net of cash acquired

  $ 654,045  
       
       

        Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired

  $ 239,251  

Value of common units issued, net of issurance costs

    414,794  
       

Total consideration paid

  $ 654,045  
       
       

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

        We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

        Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Pecos Combination

        On November 1, 2012, we completed a business combination whereby we acquired Pecos Gathering & Marketing, L.L.C. and certain of its affiliated companies (collectively, "Pecos"). The business of Pecos consists primarily of crude oil marketing and logistics operations in Texas and New Mexico. We paid $132.4 million of cash (net of cash acquired) and assumed certain obligations with a value of $10.2 million under certain equipment financing facilities. Also on November 1, 2012, we entered into a call agreement with the former owners of Pecos pursuant to which the former owners of Pecos agreed to purchase a minimum of $45.0 million or a maximum of $60.0 million of common units from us. On November 12, 2012, the former owners purchased 1,834,414 common units from us for $45.0 million pursuant to this call agreement. We incurred and charged to general and administrative expense during the year ended March 31, 2013 $0.6 million of costs related to the Pecos combination.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

        The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of Pecos:

 
  Final   Estimated at
March 31, 2013
  Change  
 
  (in thousands)
 

Accounts receivable—trade

  $ 73,609   $ 73,704   $ (95 )

Inventories

    1,903     1,903      

Prepaid expenses and other current assets

    1,426     1,426      

Property, plant and equipment:

                   

Vehicles (5 - 10 years)

    22,097     19,193     2,904  

Buildings and leasehold improvements (5 - 30 years)

    1,339     1,248     91  

Crude oil tanks and related equipment (2 - 15 years)

    1,099     913     186  

Land

    223     224     (1 )

Other (3 - 5 years)

    36     177     (141 )

Intangible assets:

                   

Customer relationships

        8,000     (8,000 )

Trade names (indefinite life)

    900     1,000     (100 )

Goodwill

    91,747     86,661     5,086  

Accounts payable—trade

    (50,795 )   (50,808 )   13  

Accrued expenses and other payables

    (963 )   (1,020 )   57  

Long-term debt

    (10,234 )   (10,234 )    
               

Fair value of net assets acquired

  $ 132,387   $ 132,387   $  
               
               

        Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired

  $ 87,444  

Value of common units issued

    44,943  
       

Total consideration paid

  $ 132,387  
       
       

        Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Third Coast Combination

        On December 31, 2012, we completed a business combination transaction whereby we acquired all of the membership interests in Third Coast Towing, LLC ("Third Coast") for $43.0 million in cash. The business of Third Coast consists primarily of transporting crude oil via barge. Also on December 31, 2012, we entered into a call agreement with the former owners of Third Coast pursuant to which the former owners of Third Coast agreed to purchase a minimum of $8.0 million or a maximum of

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

$10.0 million of common units from us. On January 11, 2013, the former owners of Third Coast purchased 344,680 common units from us for $8.0 million pursuant to this agreement.

        During the year ended March 31, 2014, we completed the acquisition accounting for this business combination. The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of Third Coast:

 
  Final   Estimated at
March 31,
2013
  Change  
 
  (in thousands)
 

Accounts receivable—trade

  $ 2,195   $ 2,248   $ (53 )

Inventories

    140     140      

Property, plant and equipment:

                   

Barges and towboats (20 years)

    17,711     12,883     4,828  

Other

        30     (30 )

Intangible assets:

                   

Customer relationships (3 years)

    3,000     4,000     (1,000 )

Trade names (indefinite life)

    850     500     350  

Goodwill

    18,847     22,551     (3,704 )

Other noncurrent assets

    2,733     2,733      

Accounts payable—trade

    (2,429 )   (2,048 )   (381 )

Accrued expenses and other payables

    (164 )   (154 )   (10 )
               

Fair value of net assets acquired

  $ 42,883   $ 42,883   $  
               
               

        Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired

  $ 35,000  

Value of common units issued

    7,883  
       

Total consideration paid

  $ 42,883  
       
       

        Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Other Crude Oil Logistics and Water Solutions Business Combinations

        During the year ended March 31, 2013, we completed four separate acquisitions to expand the assets and operations of our crude oil logistics and water solutions businesses. On a combined basis, we paid $52.6 million in cash and assumed $1.3 million of long-term debt in the form of non-compete agreements. We also issued 516,978 common units, valued at $12.4 million, as partial consideration for one of these acquisitions. We incurred and charged to general and administrative expense during the year ended March 31, 2013 $0.3 million of costs related to these acquisitions.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

        During the year ended March 31, 2014, we completed the acquisition accounting for these business combinations. The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of these businesses:

 
  Final   Estimated at
March 31,
2013
  Change  
 
  (in thousands)
 

Accounts receivable—trade

  $ 2,676   $ 2,660   $ 16  

Inventories

    191     191      

Prepaid expenses and other current assets

    737     738     (1 )

Property, plant and equipment:

                   

Land

    218     191     27  

Vehicles (5 - 10 years)

    853     771     82  

Water treatment facilities and equipment (3 - 30 years)

    13,665     13,322     343  

Buildings and leasehold improvements (5 - 30 years)

    895     2,233     (1,338 )

Crude oil tanks and related equipment (2 - 15 years)

    4,510     1,781     2,729  

Other (3 - 5 years)

    27     2     25  

Construction in progress

    490     693     (203 )

Intangible assets:

                   

Customer relationships (5 - 10 years)

    13,125     6,800     6,325  

Non-compete agreements (3 years)

    164     510     (346 )

Trade names (indefinite life)

    2,100     500     1,600  

Goodwill

    34,451     43,822     (9,371 )

Accounts payable—trade

    (3,374 )   (3,374 )    

Accrued expenses and other payables

    (1,914 )   (2,026 )   112  

Notes payable

    (1,340 )   (1,340 )    

Other noncurrent liabilities

    (156 )   (156 )    

Noncontrolling interest

    (2,333 )   (2,333 )    
               

Fair value of net assets acquired

  $ 64,985   $ 64,985   $  
               
               

        Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired

  $ 52,552  

Value of common units issued

    12,433  
       

Total consideration paid

  $ 64,985  
       
       

        Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

Retail Propane Combinations During the Year Ended March 31, 2013

        During the year ended March 31, 2013, we entered into six separate business combination agreements to acquire retail propane and distillate operations, primarily in the northeastern and southeastern United States. On a combined basis, we paid cash of $71.4 million and issued 850,676 common units, valued at $18.9 million, in exchange for these assets. We also assumed $6.6 million of long-term debt in the form of non-compete agreements. We incurred and charged to general and administrative expense during the year ended March 31, 2013 $0.3 million related to these acquisitions. The fair values of the assets acquired and liabilities assumed in these six combinations are as follows (in thousands):

Accounts receivable—trade

  $ 8,715  

Inventory

    5,155  

Other current assets

    1,228  

Property, plant and equipment:

       

Land

    1,945  

Retail propane equipment (5 - 20 years)

    28,763  

Vehicles (5 years)

    11,344  

Buildings and leasehold improvements (30 years)

    7,052  

Other

    1,201  

Intangible assets:

       

Customer relationships (10 - 15 years)

    16,890  

Trade names (indefinite)

    2,924  

Non-compete agreements (5 years)

    1,387  

Goodwill

    21,983  

Other non-current assets

    784  

Long-term debt, including current portion

    (6,594 )

Other assumed liabilities

    (12,511 )
       

Fair value of net assets acquired

  $ 90,266  
       
       

        Consideration paid consists of the following (in thousands):

Cash consideration paid

  $ 71,392  

Value of common units issued

    18,874  
       

Total consideration

  $ 90,266  
       
       

        Goodwill represents the excess of the estimated consideration paid for the acquired businesses over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

        We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

Pro Forma Results of Operations (Unaudited)

        As described above, we completed a number of acquisitions during the years ended March 31, 2014 and 2013. The operations of each acquired business have been included in our consolidated results of operations since the date of acquisition of the business. The unaudited pro forma consolidated data presented below has been prepared as if the following acquisitions had been completed on April 1, 2012:

        The unaudited pro forma consolidated data presented below has also been prepared as if the following transactions, which are described in Notes 8 and 11 to these consolidated financial statements, had been completed on April 1, 2012:

 
  Year Ended March 31,  
 
  2014   2013  
 
  (in thousands, except
per unit amounts)

 

Revenues

  $ 9,800,398   $ 5,697,988  

Net income (loss)

    798     (72,171 )

Net loss attributable to limited partners

    (14,446 )   (75,251 )

Basic and diluted loss per common unit

    (0.18 )   (0.95 )

Basic and diluted loss per subordinated unit

    (0.18 )   (0.95 )

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

        The pro forma consolidated data in the table above was prepared by adding historical results of operations of acquired businesses to our historical results of operations and making certain pro forma adjustments. The pro forma information is not necessarily indicative of the results of operations that would have occurred if the transactions had occurred on April 1, 2012, nor is it necessarily indicative of future results of operations.

        Gavilon Energy historically conducted trading operations, whereas we operate as a logistics business. Gavilon Energy's historical results of operations were subject to more volatility as a result of its trading operations than we would expect future results of operations to have under our business model. In the pro forma data in the table above, no pro forma effect was given to the change in business model from a trading business to a logistics business. Gavilon Energy historically recorded revenues net of product costs. In the pro forma table above, no pro forma effect was given to the fact that this accounting policy is different than our accounting policy.

        The pro forma net loss for the year ended March 31, 2013 in the table above includes $4.8 million of expense related to the retirement of a liability associated with a business combination that OWL completed prior to our acquisition of OWL. This non-recurring expense is not excluded from the pro forma net loss, as it does not directly result from our acquisition of OWL.

        The pro forma net loss for the year ended March 31, 2014 shown in the table above reflects depreciation and amortization expense estimates which are preliminary, as our identification of the assets and liabilities acquired, and the fair value determinations thereof, for the business combination with Gavilon Energy have not been completed.

        The pro forma losses per unit have been computed based on earnings or losses allocated to the limited partners after deducting the total earnings allocated to the general partner. To calculate earnings attributable to the general partner, we have used historical distribution amounts. For purposes of this calculation, we have assumed that the common units outstanding at March 31, 2014 were outstanding during the full years presented above.

Year Ended March 31, 2012

Osterman

        On October 3, 2011, we completed a business combination transaction with Osterman, whereby we acquired retail propane operations in the northeastern United States. We issued 4,000,000 common units and paid $94.9 million of cash, net of cash acquired, in exchange for the assets and operations of Osterman. The agreement also contemplated a post-closing payment of $4.8 million for certain specified working capital items, which was paid in November 2012. We valued the 4 million limited partner common units at $81.9 million based on the closing price of our common units on the closing date ($20.47 per unit). We incurred and charged to general and administrative expense during the year ended March 31, 2012 $0.8 million of costs incurred in connection with the Osterman transaction. We also incurred costs related to the equity issuance of $0.1 million that we charged to equity. The

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

following table presents the final allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands):

Accounts receivable—trade

  $ 9,350  

Inventories

    3,869  

Prepaid expenses and other current assets

    215  

Property, plant and equipment:

       

Land

    2,349  

Retail propane equipment (15 - 20 years)

    47,160  

Vehicles (5 - 20 years)

    7,699  

Buildings and leasehold improvements (30 years)

    3,829  

Other (3 - 5 years)

    732  

Intangible assets:

       

Customer relationships (20 years)

    54,500  

Trade names (indefinite life)

    8,500  

Non-compete agreements (7 years)

    700  

Goodwill

    52,267  

Assumed liabilities

    (9,654 )
       

Consideration paid, net of cash acquired

  $ 181,516  
       
       

        Consideration paid consists of the following (in thousands):

Cash paid at closing, net of cash acquired

  $ 94,873  

Fair value of common units issued at closing

    81,880  

Working capital payment (paid in November 2012)

    4,763  
       

Consideration paid, net of cash acquired

  $ 181,516  
       
       

        Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

        We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

SemStream

        On November 1, 2011, we completed a business combination with SemStream. We entered into this business combination in order to expand our liquids segment. SemStream contributed substantially all of its natural gas liquids business and assets to us in exchange for 8,932,031 of our limited partner

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

common units and a cash payment of $91.0 million. We have valued the 8.9 million limited partner common units at $184.8 million, based on the closing price of our common units on the closing date ($21.07) reduced by the expected present value of distributions for certain units which were not eligible for full distributions until the quarter ending September 30, 2012. In addition, in exchange for a cash contribution, SemStream acquired a 7.5% interest in our general partner. We incurred and charged to general and administrative expense during the year ended March 31, 2012 $0.7 million of costs related to the SemStream transaction. We also incurred costs of less than $0.1 million related to the equity issuance that we charged to equity.

        The acquired assets included 12 natural gas liquids terminals in Arizona, Arkansas, Indiana, Minnesota, Missouri, Montana, Washington and Wisconsin, 12 million gallons of aboveground propane storage, 3.7 million barrels of underground leased storage for natural gas liquids and a rail fleet of 350 leased and 12 owned cars.

        We have included the results of SemStream's operations in our consolidated financial statements beginning November 1, 2011. The operations of SemStream are reflected in our liquids segment.

        The following table presents the fair values of the assets acquired and liabilities assumed in the SemStream combination (in thousands):

Inventories

  $ 104,226  

Derivative assets

    3,578  

Assets held for sale

    3,000  

Prepaid expenses and other current assets

    9,833  

Property, plant and equipment:

       

Land

    3,470  

Natural gas liquids terminal assets (20 - 30 years)

    41,434  

Vehicles and railcars (5 years)

    470  

Other (5 years)

    3,326  

Investment in capital lease

    3,112  

Intangible assets:

       

Customer relationships (8 - 15 years)

    31,950  

Lease contracts (1 - 4 years)

    1,008  

Goodwill

    74,924  

Assumed current liabilities

    (4,591 )
       

Consideration paid

  $ 275,740  
       
       

        Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired operations and the Partnership, the opportunity to use the acquired businesses as a platform to expand our wholesale marketing operations, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

        We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

Pacer Combination

        On January 3, 2012, we completed a business combination with Pacer in order to expand our retail propane operations. The combination was funded with cash of $32.2 million and the issuance of 1.5 million common units. We valued the 1.5 million common units based on the closing price of our common units on the closing date. We incurred and charged to general and administrative expense during the year ended March 31, 2012 $0.7 million of costs related to the Pacer transaction. We also incurred costs of $0.1 million related to the equity issuance that we charged to equity.

        The assets contributed by Pacer consist of retail propane operations in Colorado, Illinois, Mississippi, Oregon, Utah and Washington. The contributed assets include 17 owned or leased customer service centers and satellite distribution locations. We have included the results of Pacer's operations in our consolidated financial statements beginning January 3, 2012. The operations of Pacer are reported within our retail propane segment.

        Consideration paid consists of the following (in thousands):

Cash

  $ 32,213  

Common units

    30,375  
       

Consideration paid

  $ 62,588  
       
       

        The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands):

Accounts receivable—trade

  $ 4,389  

Inventories

    965  

Prepaid expenses and other current assets

    43  

Property, plant and equipment:

       

Land

    1,967  

Retail propane equipment (15 - 20 years)

    12,793  

Vehicles (5 years)

    3,090  

Buildings and leasehold improvements (30 years)

    409  

Other (3 - 5 years)

    59  

Intangible assets:

       

Customer relationships (15 years)

    23,560  

Trade names (indefinite life)

    2,410  

Non-compete agreements

    1,520  

Goodwill

    15,782  

Assumed liabilities

    (4,399 )
       

Consideration paid

  $ 62,588  
       
       

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

        Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

        We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

North American Combination

        On February 3, 2012, we completed a business combination with North American in order to expand our retail propane operations. The combination was funded with cash of $69.8 million. We incurred and charged to general and administrative expense during the year ended March 31, 2012 $1.6 million of costs related to the North American acquisition.

        The assets acquired from North American include retail propane and distillate operations in Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, Pennsylvania, and Rhode Island.

        The following table presents the allocation of the acquisition costs to the assets acquired and liabilities assumed, based on their fair values (in thousands):

Accounts receivable—trade

  $ 10,338  

Inventories

    3,437  

Prepaid expenses and other current assets

    282  

Property, plant and equipment:

       

Land

    2,251  

Retail propane equipment (15 - 20 years)

    24,790  

Natural gas liquids terminal assets (15 - 20 years)

    1,044  

Vehicles (5 - 15 years)

    5,819  

Buildings and leasehold improvements (30 years)

    2,386  

Other (3 - 5 years)

    634  

Intangible assets:

       

Customer relationships (10 years)

    12,600  

Trade names (10 years)

    2,700  

Non-compete agreements (3 years)

    700  

Goodwill

    13,978  

Assumed liabilities

    (11,129 )
       

Consideration paid

  $ 69,830  
       
       

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

        Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

        We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

Other Acquisitions

        During the year ended March 31, 2012, we closed three additional acquisitions for cash payments of $6.4 million on a combined basis. We also assumed $0.6 million in long-term debt in the form of non-compete agreements. These operations have been included in our results of operations since the acquisition dates, and have not been material to our consolidated financial statements.

Note 5—Property, Plant and Equipment

        Our property, plant and equipment consists of the following:

 
  March 31,  
Description and Estimated Useful Lives
  2014   2013
(Note 2)
 
 
  (in thousands)
 

Natural gas liquids terminal assets (2 - 30 years)

  $ 75,141   $ 63,637  

Retail propane equipment (2 - 30 years)

    160,758     152,802  

Vehicles (3 - 25 years)

    152,676     88,173  

Water treatment facilities and equipment (3 - 30 years)

    180,985     91,944  

Crude oil tanks and related equipment (2 - 40 years)

    106,125     22,577  

Barges and towboats (5 - 40 years)

    52,217     25,963  

Information technology equipment (3 - 7 years)

    20,768     12,169  

Buildings and leasehold improvements (3 - 40 years)

    60,004     48,975  

Land

    30,241     21,815  

Linefill and tank bottoms

    13,403      

Other (5 - 30 years)

    6,341     16,104  

Construction in progress

    80,251     32,405  
           

    938,910     576,564  

Less: Accumulated depreciation

    (109,564 )   (50,127 )
           

Net property, plant and equipment

  $ 829,346   $ 526,437  
           
           

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 5—Property, Plant and Equipment (Continued)

        Depreciation expense was $59.9 million, $39.2 million and $10.6 million during the years ended March 31, 2014, 2013 and 2012, respectively. During the year ended March 31, 2014, we capitalized $0.7 million of interest expense.

Note 6—Goodwill

        The changes in the balance of goodwill were as follows:

 
  Year Ended March 31,  
 
  2014   2013   2012  
 
  (in thousands)
 

Beginning of period, as retrospectively adjusted (Note 2)

  $ 555,220   $ 167,245   $ 8,568  

Acquisitions

    551,786     387,975     158,677  
               

End of period, as retrospectively adjusted (Note 2)

  $ 1,107,006   $ 555,220   $ 167,245  
               
               

        Goodwill by reportable segment is as follows:

 
  March 31,  
 
  2014   2013  
 
  (in thousands)
 

Crude oil logistics

  $ 606,383   $ 246,345  

Water solutions

    262,203     109,470  

Liquids

    90,135     87,136  

Retail propane

    114,285     112,269  

Refined products

    22,000      

Renewables

    12,000      
           

  $ 1,107,006   $ 555,220  
           
           

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 7—Intangible Assets

        Our intangible assets consist of the following:

 
   
  March 31, 2014   March 31, 2013  
 
  Amortizable
Lives
  Gross Carrying
Amount
  Accumulated
Amortization
  Gross Carrying
Amount
(Note 2)
  Accumulated
Amortization
 
 
   
   
  (in thousands)
   
 

Amortizable—

                             

Customer relationships(1)

  3 - 20 years   $ 697,405   $ 83,261   $ 405,160   $ 30,959  

Water facility development agreement

  5 years     14,000     2,100          

Lease and other agreements

  5 - 8 years     23,920     13,190     15,210     7,018  

Non-compete agreements

  2 - 7 years     14,161     6,388     11,509     2,871  

Trade names

  1 - 10 years     15,489     3,081     2,784     326  

Debt issuance costs

  5 - 10 years     44,089     8,708     19,494     2,981  
                       

Total amortizable

        809,064     116,728     454,157     44,155  

Non-amortizable—

 

 

   
 
   
 
   
 
   
 
 

Trade names

        22,620           31,430        
                       

Total

      $ 831,684   $ 116,728   $ 485,587   $ 44,155  
                       
                       

(1)
The weighted-average remaining amortization period for customer relationship intangible assets is approximately nine years.

        Amortization expense was as follows:

 
  Year Ended March 31,  
Recorded in
  2014   2013   2012  
 
  (in thousands)
 

Depreciation and amortization

  $ 60,855   $ 29,657   $ 4,538  

Cost of sales

    6,172     5,285     800  

Interest expense

    5,727     3,375     1,277  

Loss on early extinguishment of debt

        5,769      
               

  $ 72,754   $ 44,086   $ 6,615  
               
               

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 7—Intangible Assets (Continued)

        Expected amortization of our intangible assets is as follows (in thousands):

Year Ending March 31,
   
 

2015

  $ 88,970  

2016

    83,449  

2017

    76,826  

2018

    72,857  

2019

    66,826  

Thereafter

    303,408  
       

  $ 692,336  
       
       

Note 8—Long-Term Obligations

        Our long-term debt consists of the following:

 
  March 31,  
 
  2014   2013  
 
  (in thousands)
 

Revolving credit facility—

             

Expansion capital loans

  $ 532,500   $ 441,500  

Working capital loans

    389,500     36,000  

Senior notes

    250,000     250,000  

Unsecured notes

    450,000      

Other notes payable

    14,914     21,562  
           

    1,636,914     749,062  

Less—current maturities

   
7,080
   
8,626
 
           

Long-term debt

  $ 1,629,834   $ 740,436  
           
           

Credit Agreement

        On June 19, 2012, we entered into a credit agreement (as amended, the "Credit Agreement") with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the "Working Capital Facility") and a revolving credit facility to fund acquisitions and expansion projects (the "Expansion Capital Facility," and together with the Working Capital Facility, the "Revolving Credit Facility").

        The Working Capital Facility had a total capacity of $935.5 million for cash borrowings and letters of credit at March 31, 2014. At March 31, 2014, we had outstanding cash borrowings of $389.5 million and outstanding letters of credit of $270.6 million on the Working Capital Facility. The Expansion Capital Facility had a total capacity of $785.5 million for cash borrowings at March 31, 2014. At March 31, 2014, we had outstanding cash borrowings of $532.5 million on the Expansion Capital Facility. The capacity available under the Working Capital Facility may be limited by a "borrowing

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 8—Long-Term Obligations (Continued)

base," as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time.

        The commitments under the Credit Agreement expire on November 5, 2018. We have the right to pre-pay outstanding borrowings under the Credit Agreement without incurring any penalties, and pre-payments of principal may be required if we enter into certain transactions to sell assets or obtain new borrowings.

        All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 0.50% to 1.50% per annum or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At March 31, 2014, the interest rate in effect on outstanding LIBOR borrowings was 1.91%, calculated as the LIBOR rate of 0.16% plus a margin of 1.75%. At March 31, 2014, the interest rate in effect on letters of credit was 1.75%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. At March 31, 2014, our outstanding borrowings and interest rates under our Revolving Credit Facility were as follows (dollars in thousands):

 
  Amount   Rate  

Expansion capital facility—

             

LIBOR borrowings

  $ 532,500     1.91 %

Working capital facility—

             

LIBOR borrowings

    358,000     1.91 %

Base rate borrowings

    31,500     4.00 %

        The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our "leverage ratio," as defined in the Credit Agreement, cannot exceed 4.25 to 1.0 at any quarter end. At March 31, 2014, our leverage ratio was approximately 3 to 1. The Credit Agreement also specifies that our "interest coverage ratio," as defined in the Credit Agreement, cannot be less than 2.75 to 1 as of the last day of any fiscal quarter. At March 31, 2014, our interest coverage ratio was approximately 7 to 1.

        The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.

        At March 31, 2014, we were in compliance with the covenants under the Credit Agreement.

Senior Notes

        On June 19, 2012, we entered into a note purchase agreement (as amended, the "Note Purchase Agreement") whereby we issued $250.0 million of senior notes in a private placement (the "Senior Notes"). The Senior Notes have an aggregate principal amount of $250.0 million and bear interest at a

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 8—Long-Term Obligations (Continued)

fixed rate of 6.65%. Interest is payable quarterly. The Senior Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to pre-pay outstanding principal, although we would incur a pre-payment penalty. The Senior Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

        The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create or permit certain liens, (iv) create or permit restrictions on the ability of certain of our subsidiaries to pay dividends or make other distributions to us, (v) enter into transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate or merge or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains the same leverage ratio and interest coverage ratio requirements as our Credit Agreement, which are described above.

        The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary grace and cure periods): (i) non-payment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the Senior Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the Note Purchase Agreement, the Senior Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregate principal amount of the then outstanding Senior Notes of any series may declare all of the Senior Notes of such series to be due and payable immediately.

        At March 31, 2014, we were in compliance with the covenants under the Note Purchase Agreement and the Senior Notes.

Unsecured Notes

        On October 16, 2013, we issued $450.0 million of 6.875% senior unsecured notes (the "Unsecured Notes") in a private placement exempt from registration under the Securities Act of 1933, as amended (the "Securities Act"), pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $438.4 million, after the initial purchasers' discount of $10.1 million and estimated offering costs of $1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

        The Unsecured Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the Unsecured Notes prior to the maturity date, although we would be required to pay a premium for early redemption.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 8—Long-Term Obligations (Continued)

        The purchase agreement and the indenture governing the Unsecured Notes contain various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

        At March 31, 2014, we were in compliance with the covenants under the Unsecured Notes.

        We also entered into a registration rights agreement whereby we have committed to exchange the Unsecured Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the Unsecured Notes on or before October 16, 2014. If we are unable to fulfill this obligation, we would be required to pay liquidated damages to the holders of the Unsecured Notes.

Other Notes Payable

        We have executed various non-interest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also have certain notes payable related to equipment financing, which have interest rates ranging from 2.1% to 4.9% at March 31, 2014.

Debt Maturity Schedule

        The scheduled maturities of our long-term debt are as follows at March 31, 2014:

Year Ending March 31,
  Revolving
Credit
Facility
  Senior
Notes
  Unsecured
Notes
  Other
Notes
Payable
  Total  
 
   
   
  (in thousands)
   
   
 

2015

  $   $   $   $ 7,081   $ 7,081  

2016

                3,614     3,614  

2017

                2,356     2,356  

2018

        25,000         1,449     26,449  

2019

    922,000     50,000         238     972,238  

Thereafter

        175,000     450,000     176     625,176  
                       

  $ 922,000   $ 250,000   $ 450,000   $ 14,914   $ 1,636,914  
                       
                       

Previous Credit Facilities

        On June 19, 2012, we made a principal payment of $306.8 million to retire our previous revolving credit facility. Upon retirement of this facility, we wrote off the portion of the debt issuance cost asset that had not yet been amortized. This expense is reported as "Loss on early extinguishment of debt" in our consolidated statement of operations for the year ended March 31, 2013.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 9—Income Taxes

        We believe that we qualify as a partnership for income tax purposes. As such, we generally do not pay United States federal income tax. Rather, each owner reports his or her share of our income or loss on his or her individual tax return. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined, as we do not have access to information regarding each partner's basis in the Partnership.

        We have certain taxable corporate subsidiaries in the United States and Canada. In addition, our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales.

        A publicly traded partnership is required to generate at least 90% of its gross income (as defined for federal income tax purposes) from certain qualifying sources. Income generated by our taxable corporate subsidiaries is excluded from this qualifying income calculation. Although we routinely generate income outside of our corporate subsidiaries that is non-qualifying, we believe that at least 90% of our gross income has been qualifying income for each of the calendar years since our IPO.

        We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in the consolidated financial statements at March 31, 2014.

Note 10—Commitments and Contingencies

Legal Contingencies

        We are party to various claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of our management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of our liabilities may change materially as circumstances develop.

Customer Dispute

        A customer of our crude oil logistics segment has disputed the transportation rate schedule we used to bill the customer for services that we provided from November 2012 through February 2013, which was the same rate schedule that Pecos used to bill the customer from April 2011 through October 2012 (prior to our acquisition of Pecos). The customer has not paid $1.7 million of the amount we charged for services we provided from November 2012 through February 2013. In May 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. Later in May 2013, the customer filed an answer and counterclaim seeking to recover $5.5 million that it paid to Pecos prior to our acquisition of Pecos. We have not recorded revenue for the $1.7 million of unpaid fees charged from November 2012 through February 2013, pending resolution of the dispute.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 10—Commitments and Contingencies (Continued)

        During August 2013, the customer notified us that it intended to withhold payment of $3.3 million for services performed by us during the period from June 2013 through August 2013, pending resolution of the dispute, although the customer has not disputed the validity of the amounts billed for services performed during this time frame. Upon receiving this notification, we ceased providing services under this contract, and on November 5, 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. We are not able to reliably predict the outcome of this dispute at this time, but we do not believe the outcome will have a material adverse effect on our consolidated financial position or results of operations.

Canadian Fuel and Sales Taxes

        The taxing authority of a province in Canada completed an audit of fuel and sales tax payments and alleged that an entity we acquired should have collected from customers and remitted to the taxing authority fuel and sales taxes on certain historical sales. We recorded in the acquisition accounting a liability of $0.8 million (net of receivables for expected recoveries from other parties). We now believe this matter is resolved, and we removed the liability from our consolidated balance sheet and recorded a corresponding reduction to cost of sales during the year ended March 31, 2014.

Environmental Matters

        Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there can be no assurance that significant costs will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

Asset Retirement Obligations

        We have recorded a liability of $2.3 million at March 31, 2014 for asset retirement obligations. This liability is related to wastewater disposal facilities and crude oil facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

        In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certain other assets. However, we do not believe the present value of these asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of our facilities, is material to our consolidated financial position or results of operations.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 10—Commitments and Contingencies (Continued)

Operating Leases

        We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, and equipment. Future minimum lease payments under contractual commitments at March 31, 2014 are as follows (in thousands):

Year Ending March 31,
   
 

2015

  $ 133,170  

2016

    93,454  

2017

    64,209  

2018

    49,802  

2019

    29,213  

Thereafter

    58,182  
       

Total

  $ 428,030  
       
       

        Rental expense relating to operating leases was $98.3 million, $84.2 million, and $5.2 million during the years ended March 31, 2014, 2013, and 2012, respectively.

Sales and Purchase Contracts

        We have entered into sales and purchase contracts for products to be delivered in future periods for which we expect the parties to physically settle the contracts with inventory. At March 31, 2014, we had the following such commitments outstanding:

 
  Volume   Value  
 
  (in thousands)
 

Natural gas liquids fixed-price purchase commitments (gallons)

    31,111   $ 39,117  

Natural gas liquids floating-price purchase commitments (gallons)

    522,947     618,293  

Natural gas liquids fixed-price sale commitments (gallons)

    63,944     77,682  

Natural gas liquids floating-price sale commitments (gallons)

    272,495     395,095  

Crude oil fixed-price purchase commitments (barrels)

    4,016     364,557  

Crude oil fixed-price sale commitments (barrels)

    3,574     324,765  

        We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs. Contracts in the table above may have offsetting derivative contracts (described in Note 12) or inventory positions (described in Note 2).

        Certain other forward purchase and sale contracts do not qualify for the normal purchase and normal sale election. These contracts are recorded at fair value on our consolidated balance sheet and are not included in the data in the table above. These contracts are included in the derivative disclosures in Note 12, and represent $43.5 million of our prepaid expenses and other current assets and $34.6 million of our accrued expenses and other payables at March 31, 2014.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 11—Equity

Partnership Equity

        The Partnership's equity consists of a 0.1% general partner interest and a 99.9% limited partner interest. Limited partner equity includes common and subordinated units. The common and subordinated units share equally in the allocation of income or loss. The principal difference between common and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

        We expect the subordination period to end in August 2014. When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages.

        Our general partner is not obligated to make any additional capital contributions or to guarantee or pay any of our debts and obligations.

Initial Public Offering

        On May 17, 2011, we completed our IPO. We sold a total of 4,025,000 common units in our IPO at $21.00 per unit. Our proceeds from the sale of 3,850,000 common units of $71.9 million, net of total offering costs of $9.0 million, were used to repay advances under our acquisition credit facility and for general partnership purposes. Proceeds from the sale of 175,000 common units ($3.4 million) from the underwriters' exercise of their option to purchase additional common units from us were used to redeem 175,000 of the common units outstanding prior to our IPO. Upon the completion of our IPO and the underwriters' exercise in full of their option to purchase additional common units from us and the redemption, we had outstanding 8,864,222 common units, 5,919,346 subordinated units, a 0.1% general partner interest, and IDRs.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 11—Equity (Continued)

Common Units Issued in Business Combinations

        As described in Note 4, we issued common units as partial consideration for several acquisitions. These are summarized below:

Osterman combination

    4,000,000  

SemStream combination

    8,932,031  

Pacer combination

    1,500,000  
       

Total—Year Ended March 31, 2012

    14,432,031  
       
       

High Sierra combination

    20,703,510  

Retail propane combinations

    850,676  

Crude oil logistics and water solutions combinations

    516,978  

Pecos combination

    1,834,414  

Third Coast combination

    344,680  
       

Total—Year Ended March 31, 2013

    24,250,258  
       
       

Water solutions combinations

    222,381  

Crude oil logistics combinations

    175,211  

OWL combination

    2,463,287  
       

Total—Year Ended March 31, 2014

    2,860,879  
       
       

        In connection with the completion of certain of these transactions, we amended our Registration Rights Agreement, which provides for certain registration rights for certain holders of our common units.

Equity Issuances

        On July 5, 2013, we completed a public offering of 10,350,000 common units. We received net proceeds of $287.5 million, after underwriting discounts and commissions of $12.0 million and offering costs of $0.7 million.

        On September 25, 2013, we completed a public offering of 4,100,000 common units. We received net proceeds of $127.6 million, after underwriting discounts and commissions of $5.0 million and offering costs of $0.2 million.

        On December 2, 2013, we issued and sold 8,110,848 of our common units in a private placement. We received net proceeds of $235.1 million, after offering costs of $4.9 million.

Distributions

        Our general partner has adopted a cash distribution policy that will require us to pay a quarterly distribution to the extent we have sufficient cash from operations after establishment of cash reserves

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 11—Equity (Continued)

and payment of fees and expenses, including payments to the general partner and its affiliates, referred to as "available cash," in the following manner:

        The general partner will also receive, in addition to distributions on its 0.1% general partner interest, additional distributions based on the level of distributions paid to the limited partners. These distributions are referred to as "incentive distributions."

        The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution per Unit." The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1% general partner interest, assume our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and has not transferred its IDRs and there are no arrearages on common units.

 
   
   
   
   
  Marginal Percentage
Interest In Distributions
 
 
  Total Quarterly Distribution per Unit   Unitholders   General Partner  

Minimum quarterly distribution

                $ 0.337500     99.9 %   0.1 %

First target distribution

  above   $ 0.337500   up to   $ 0.388125     99.9 %   0.1 %

Second target distribution

  above   $ 0.388125   up to   $ 0.421875     86.9 %   13.1 %

Third target distribution

  above   $ 0.421875   up to   $ 0.506250     76.9 %   23.1 %

Thereafter

  above   $ 0.506250               51.9 %   48.1 %

        On May 5, 2011, we made a distribution of $3.9 million from available cash to our general partner and common unitholders at March 31, 2011.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 11—Equity (Continued)

        The following table summarizes the distributions declared subsequent to our IPO:

Date Declared
  Record Date   Date Paid   Amount
Per Unit
  Amount Paid to
Limited Partners
  Amount Paid to
General Partner
 
 
   
   
   
  (in thousands)
  (in thousands)
 

July 25, 2011

  August 3, 2011   August 12, 2011   $ 0.1669   $ 2,467   $ 3  

October 21, 2011

  October 31, 2011   November 14, 2011     0.3375     4,990     5  

January 24, 2012

  February 3, 2012   February 14, 2012     0.3500     7,735     10  

April 18, 2012

  April 30, 2012   May 15, 2012     0.3625     9,165     10  

July 24, 2012

  August 3, 2012   August 14, 2012     0.4125     13,574     134  

October 17, 2012

  October 29, 2012   November 14, 2012     0.4500     22,846     707  

January 24, 2013

  February 4, 2013   February 14, 2013     0.4625     24,245     927  

April 25, 2013

  May 6, 2013   May 15, 2013     0.4775     25,605     1,189  

July 25, 2013

  August 5, 2013   August 14, 2013     0.4938     31,725     1,739  

October 23, 2013

  November 4, 2013   November 14, 2013     0.5113     35,908     2,491  

January 23, 2014

  February 4, 20143   February 14, 2014     0.5313     42,150     4,283  

April 24, 2014

  May 5, 2014   May 15, 2014     0.5513     43,737     5,754  

        Several of our business combination agreements contained provisions that temporarily limited the distributions to which the newly-issued units were entitled. The following table summarizes the number of equivalent units that were not eligible to receive a distribution on each of the record dates:

Record Date
  Equivalent
Units
Not Eligible
 

August 3, 2011

     

October 31, 2011

    4,000,000  

February 3, 2012

    7,117,031  

April 30, 2012

    3,932,031  

August 3, 2012

    17,862,470  

October 29, 2012

    516,978  

February 4, 2013

    1,202,085  

May 6, 2013

     

August 5, 2013

     

November 4, 2013

    979,886  

February 4, 2014

     

May 5, 2014

     

Equity-Based Incentive Compensation

        Our general partner has adopted a long-term incentive plan ("LTIP") which allows for the issuance of equity-based compensation to employees and directors. The board of directors of our general partner has granted certain restricted units to employees and directors, which will vest in tranches, subject to the continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 11—Equity (Continued)

        The following table summarizes the restricted unit activity during the years ended March 31, 2014 and 2013:

Unvested restricted units at March 31, 2012

     

Units granted

    1,684,400  

Units vested and issued

    (156,802 )

Units withheld for employee taxes

    (61,698 )

Units forfeited

    (21,000 )
       

Unvested restricted units at March 31, 2013

    1,444,900  

Units granted

    494,000  

Units vested and issued

    (296,269 )

Units withheld for employee taxes

    (122,531 )

Units forfeited

    (209,000 )
       

Unvested restricted units at March 31, 2014

    1,311,100  
       
       

        The scheduled vesting of the awards is summarized below:

Vesting Date
  Number of
Awards
 

July 1, 2014

    408,300  

January 1, 2015

    4,000  

July 1, 2015

    341,300  

January 1, 2016

    4,000  

July 1, 2016

    322,500  

January 1, 2017

    4,000  

July 1, 2017

    192,500  

January 1, 2018

    4,000  

July 1, 2018

    30,500  
       

Total unvested units at March 31, 2014

    1,311,100  
       
       

        We record the expense for each tranche on a straight-line basis over the period beginning with the vesting of the previous tranche and ending with the vesting of the tranche. We adjust the cumulative expense recorded through the reporting date using the estimated fair value of the awards at the reporting date. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth. We estimate that the future expense we will record on the unvested awards at March 31, 2014 will be as follows (in thousands), after taking into consideration an estimate

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 11—Equity (Continued)

of forfeitures of 95,000 units. For purposes of this calculation, we have used the closing price of the common units on March 31, 2014, which was $37.53.

Year Ending March 31,
   
 

2015

  $ 14,393  

2016

    11,279  

2017

    7,429  

2018

    2,310  

2019

    229  
       

Total

  $ 35,640  
       
       

        Following is a rollforward of the liability related to equity-based compensation, which is reported within accrued expenses and other payables on our consolidated balance sheets (in thousands):

Balance at March 31, 2012

  $  

Expense recorded

    10,138  

Value of units vested and issued

    (3,627 )

Taxes paid on behalf of participants

    (1,468 )
       

Balance at March 31, 2013

    5,043  

Expense recorded

    17,804  

Value of units vested and issued

    (9,085 )

Taxes paid on behalf of participants

    (3,750 )
       

Balance at March 31, 2014

  $ 10,012  
       
       

        The weighted-average fair value of the awards at March 31, 2014 was $33.78, which was calculated as the closing price of the common units on March 31, 2014, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth.

        The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common and subordinated units. The maximum number of units deliverable under the plan automatically increases to 10% of the issued and outstanding common and subordinated units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount. Units withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, if an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available for new awards under the LTIP. At March 31, 2014, 6.2 million units remain available for issuance under the LTIP.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 12—Fair Value of Financial Instruments

        Our cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, and other current liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values, due to their short-term nature. We believe the carrying amounts of our long-term debt instruments, including the Revolving Credit Facility and the Senior Notes, approximate their fair values, as we do not believe market conditions have changed materially since we entered into these debt agreements.

Commodity Derivatives

        The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2014:

 
  Derivative
Assets
  Derivative
Liabilities
 
 
  (in thousands)
 

Level 1 measurements

  $ 4,990   $ (3,258 )

Level 2 measurements

    49,605     (43,303 )
           

    54,595     (46,561 )

Netting of counterparty contracts(1)

    (4,347 )   4,347  

Cash collateral provided or held

    456      
           

Commodity contracts reported on consolidated balance sheet

  $ 50,704   $ (42,214 )
           
           

(1)
Relates to derivative assets and liabilities that are expected to be net settled on an exchange or through a master netting arrangement with the counterparty.

        The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2013:

 
  Derivative
Assets
  Derivative
Liabilities
 
 
  (in thousands)
 

Level 1 measurements

  $ 947   $ (3,324 )

Level 2 measurements

    9,911     (13,280 )
           

    10,858     (16,604 )

Netting of counterparty contracts(1)

    (3,503 )   3,503  

Cash collateral provided or held

    (1,760 )   400  
           

Commodity contracts reported on consolidated balance sheet

  $ 5,595   $ (12,701 )
           
           

(1)
Relates to derivative assets and liabilities that are expected to be net settled on an exchange or through a master netting arrangement with the counterparty.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 12—Fair Value of Financial Instruments (Continued)

        The commodity derivative assets (liabilities) are reported in the following accounts on the consolidated balance sheets:

 
  March 31,  
 
  2014   2013  
 
  (in thousands)
 

Prepaid expenses and other current assets

  $ 50,704   $ 5,551  

Other noncurrent assets

        44  

Accrued expenses and other payables

    (42,214 )   (12,701 )
           

Net asset (liability)

  $ 8,490   $ (7,106 )
           
           

        The following table sets forth our open commodity derivative contract positions at March 31, 2014 and 2013. We do not account for these derivatives as hedges.

Contracts
  Settlement Period   Total
Notional
Units
(Barrels)
  Fair Value
of Net Assets
(Liabilities)
 
 
   
  (in thousands)
 

At March 31, 2014—

                 

Cross-commodity(1)

  April 2014 - March 2015     140   $ (1,876 )

Crude oil fixed-price(2)

  April 2014 - March 2015     (1,600 )   (2,796 )

Crude oil index(3)

  April 2014 - December 2015     3,598     6,099  

Propane fixed-price(4)

  April 2014 - March 2015     60     1,753  

Refined products fixed-price(5)

  April 2014 - July 2014     732     560  

Renewable products fixed-price(6)

  April 2014 - July 2014     106     4,084  

Other

  April 2014         210  
                 

              8,034  

Net cash collateral provided

              456  
                 

Net value of commodity derivatives on consolidated balance sheet

            $ 8,490  
                 
                 

At March 31, 2013—

                 

Cross-commodity(1)

  April 2013 - March 2014     430   $ (10,208 )

Crude oil fixed-price(2)

  April 2013 - March 2014     (144 )   1,033  

Crude oil index(3)

  April 2013 - June 2014     (91 )   153  

Propane fixed-price(4)

  April 2013 - March 2014     (282 )   3,197  

Other

  May 2013 - June 2013     8     79  
                 

              (5,746 )

Net cash collateral held

              (1,360 )
                 

Net value of commodity derivatives on consolidated balance sheet

            $ (7,106 )
                 
                 

(1)
Cross-commodity—Our operating segments may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. The contracts

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 12—Fair Value of Financial Instruments (Continued)

(2)
Crude oil fixed-price—Our crude oil logistics segment routinely purchases crude oil inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as "Crude oil fixed-price" represent derivatives we have entered into as an economic hedge against the risk that crude oil prices will decline while we are holding the inventory.

(3)
Crude oil index—Our crude oil logistics segment may purchase or sell crude oil where the underlying contract pricing mechanisms are tied to different crude oil indices. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. The contracts listed in this table as "Crude oil index" represent derivatives we have entered into as an economic hedge against the risk of one crude oil index moving relative to another crude oil index.

(4)
Propane fixed-price—Our liquids segment routinely purchases inventory during the warmer months and stores the inventory for sale in the colder months. The contracts listed in this table as "Propane fixed-price" represent derivatives we have entered into as an economic hedge against the risk that propane prices will decline while we are holding the inventory.

(5)
Refined products fixed-price—Our refined products segment routinely purchases refined products inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as "Refined products fixed-price" represent derivatives we have entered into as an economic hedge against the risk that refined product prices will decline while we are holding the inventory.

(6)
Renewable products fixed-price—Our renewables segment routinely purchases biodiesel and ethanol inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as "Renewable products fixed-price" represent derivatives we have entered into as an economic hedge against the risk that biodiesel or ethanol prices will decline while we are holding the inventory.

        We recorded the following net gains (losses) from our commodity derivatives to cost of sales:

Year Ended March 31,
   
 

2014

  $ (43,655 )

2013

    (4,381 )

2012

    5,676  

Credit Risk

        We maintain credit policies with regard to our counterparties on the derivative financial instruments that we believe minimize our overall credit risk, including an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single counterparty.

        We may enter into industry standard master netting agreements and may enter into cash collateral agreements requiring the counterparty to deposit funds into a brokerage margin account. The netting agreements reduce our credit risk by providing for net settlement of any offsetting positive and negative

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 12—Fair Value of Financial Instruments (Continued)

exposures with counterparties. The cash collateral agreements reduce the level of our net counterparty credit risk because the amount of collateral represents additional funds that we may access to net settle positions due us, and the amount of collateral adjusts each day in response to changes in the market value of counterparty derivatives.

        Our counterparties consist primarily of financial institutions and energy companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

        As is customary in the crude oil industry, we generally receive payment from customers on a monthly basis. As a result, receivables from individual customers in our crude oil logistics are typically higher than the receivables from customers of our other segments.

        Failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated statements of financial position and recognized in our net income.

Interest Rate Risk

        Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At March 31, 2014, we have $922.0 million of outstanding borrowings under our Revolving Credit Facility at a rate of 1.98%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.2 million on the $922.0 million of outstanding borrowings on the revolving credit facility at March 31, 2014.

Note 13—Segments

        Our reportable segments are based on the way in which our management structure is organized. Certain financial data related to our segments is shown below. Transactions between segments are recorded based on prices negotiated between the segments.

        Our crude oil logistics segment sells crude oil and provides crude oil transportation services to wholesalers, refiners, and producers. Our water solutions segment provides services for the transportation, treatment, and disposal of wastewater generated from crude oil and natural gas production, and generates revenue from the sale of recycled wastewater and recovered hydrocarbons. Our liquids segment supplies propane, butane, and other products, and provides natural gas liquids transportation, terminaling, and storage services to retailers, wholesalers, and refiners. Our retail propane segment sells propane and distillates to end users consisting of residential, agricultural, commercial, and industrial customers, and to certain re-sellers. Our retail propane segment consists of two divisions, which are organized based on the location of the operations.

        We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products in back-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business, which purchases ethanol primarily at production facilities, and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwest

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 13—Segments (Continued)

and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders. These businesses were acquired in our December 2013 acquisition of Gavilon Energy.

        Items labeled "corporate and other" in the table below include the operations of a compressor leasing business that we acquired in our June 2012 merger with High Sierra and sold in February 2014, and the natural gas marketing operations that we acquired in our December 2013 acquisition of Gavilon Energy and began winding down during fiscal 2014. The "corporate and other" category also includes certain corporate expenses that are incurred and are not allocated to the reportable segments. This data is included to reconcile the data for the reportable segments to data in our consolidated financial statements.

        Certain information related to the results of operations of each segment is shown in the tables below:

 
  Year Ended March 31,  
 
  2014   2013   2012  
 
  (in thousands)
 

Revenues:

                   

Crude oil logistics—

                   

Crude oil sales

  $ 4,559,923   $ 2,322,706   $  

Crude oil transportation and other

    36,469     16,442      

Water solutions—

                   

Water treatment and disposal

    125,788     54,334      

Water transportation

    17,312     7,893      

Liquids—

                   

Propane sales

    1,632,948     841,448     923,022  

Other product sales

    1,231,965     858,276     251,627  

Other revenues

    31,062     33,954     2,462  

Retail propane—

                   

Propane sales

    388,225     288,410     175,417  

Distillate sales

    127,672     106,192     6,547  

Other revenues

    35,918     35,856     17,370  

Refined products

    1,180,895          

Renewables

    176,781          

Corporate and other

    437,713     4,233      

Eliminations of intersegment sales

    (283,397 )   (151,977 )   (65,972 )
               

Total revenues

  $ 9,699,274   $ 4,417,767   $ 1,310,473  
               
               

Depreciation and amortization:

                   

Crude oil logistics

  $ 22,111   $ 9,176   $  

Water solutions

    55,105     20,923      

Liquids

    11,018     11,085     3,661  

Retail propane

    28,878     25,496     11,450  

Refined products

    109          

Renewables

    516          

Corporate and other

    3,017     2,173      
               

Total depreciation and amortization

  $ 120,754   $ 68,853   $ 15,111  
               
               

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 13—Segments (Continued)

 
  Year Ended March 31,  
 
  2014   2013   2012  
 
  (in thousands)
 

Operating income (loss):

                   

Crude oil logistics

  $ 678   $ 34,236   $  

Water solutions

    10,317     8,576      

Liquids

    71,888     30,336     9,735  

Retail propane

    61,285     46,869     9,616  

Refined products

    4,080          

Renewables

    2,434          

Corporate and other

    (44,117 )   (32,710 )   (4,321 )
               

Total operating income

  $ 106,565   $ 87,307   $ 15,030  
               
               

        The table below shows additions to property, plant and equipment for each segment. This information has been prepared on the accrual basis, and includes property, plant and equipment acquired in acquisitions.

 
  Year Ended March 31,  
 
  2014   2013   2012  
 
  (in thousands)
 

Additions to property, plant and equipment, including acquisitions (accrual basis):

                   

Crude oil logistics

  $ 204,642   $ 89,860   $  

Water solutions

    100,877     137,116      

Liquids

    52,560     15,129     50,276  

Retail propane

    24,430     66,933     150,181  

Refined products

    719          

Renewables

    519          

Corporate and other

    7,242     17,858      
               

Total

  $ 390,989   $ 326,896   $ 200,457  
               
               

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 13—Segments (Continued)

        The following tables show long-lived assets (consisting of property, plant and equipment, intangible assets, and goodwill) and total assets by segment:

 
  March 31,  
 
  2014   2013
(Note 2)
 
 
  (in thousands)
 

Total assets:

             

Crude oil logistics

  $ 1,723,812   $ 801,351  

Water solutions

    875,714     466,412  

Liquids

    577,795     474,141  

Retail propane

    541,832     513,301  

Refined products

    157,581      

Renewables

    145,649      

Corporate and other

    144,840     36,413  
           

Total

  $ 4,167,223   $ 2,291,618  
           
           

Long-lived assets, net:

             

Crude oil logistics

  $ 980,978   $ 357,230  

Water solutions

    848,479     453,909  

Liquids

    274,846     238,192  

Retail propane

    438,324     441,762  

Refined products

    27,017      

Renewables

    33,703      

Corporate and other

    47,961     31,996  
           

Total

  $ 2,651,308   $ 1,523,089  
           
           

Note 14—Disposals and Impairments

        We acquired Gavilon Energy in December 2013, which operated a natural gas marketing business. During March 2014, we assigned all of the storage and transportation contracts of the natural gas marketing business to a third party. Since these contracts were at unfavorable terms relative to current market conditions, we paid $44.8 million to assign these contracts. We recorded a liability of $50.8 million related to these storage and transportation contracts in the acquisition accounting, and we amortized $6.0 million of this balance through cost of sales during the period from the acquisition date through the date we assigned the contracts. We also assigned all forward purchase and sale contracts and all financial derivative contracts, and thereby wound down the natural gas business. Our consolidated statement of operations for the year ended March 31, 2014 includes $1.4 million of operating income related to the natural gas business, which is reported within "corporate and other" in the segment disclosures in Note 13.

        We acquired High Sierra in June 2012, which operated a compressor leasing business. We sold the compressor leasing business in February 2014 for $10.8 million (net of the amount due to the owner of the noncontrolling interest in the business). We recorded a gain on the sale of the business of $4.4 million, $1.6 million of which was attributable to the disposal of the noncontrolling interest. We

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 14—Disposals and Impairments (Continued)

reported the gain as a reduction to operating expenses in our consolidated statement of operations. Our consolidated statement of operations for the year ended March 31, 2014 includes $2.3 million of operating income related to the compressor leasing business, which is reported within "corporate and other" in the segment disclosures in Note 13.

        During the year ended March 31, 2014, we recorded an impairment of $5.3 million to the property, plant and equipment of one of our natural gas liquids terminals. This loss is reported within operating expenses of our liquids segment.

        During the year ended March 31, 2014, two of our water solutions facilities experienced damage to their property, plant and equipment as a result of lightning strikes. We recorded a write-down to property, plant and equipment of $1.5 million related to these incidents, which is reported within operating expenses in our consolidated statement of operations.

Note 15—Transactions with Affiliates

        Since our business combination with SemStream on November 1, 2011, SemGroup Corporation ("SemGroup") has held ownership interests in us and in our general partner, and has the right to appoint two members to the board of directors of our general partner. Subsequent to November 1, 2011, we have sold product to and purchased product from affiliates of SemGroup. These transactions are included within revenues and cost of sales in our consolidated statements of operations.

        Certain members of our management own interests in entities with which we have purchased products and services from and have sold products and services. The majority of these purchases represent crude oil purchases and are reported within cost of sales in our consolidated statements of operations, although $8.2 million of these transactions during the year ended March 31, 2014 represented capital expenditures and were recorded as increases to property, plant and equipment. The majority of these sales represent sales of crude oil and have been recorded within revenues in our consolidated statement of operations.

        These transactions are summarized in the table below:

 
  Year Ended March 31,  
 
  2014   2013   2012  
 
  (in thousands)
 

Sales to SemGroup

  $ 306,780   $ 32,431   $ 29,200  

Purchases from SemGroup

    445,951     60,425     23,800  

Sales to entities affiliated with management

    110,824     16,828      

Purchases from entities affiliated with management

    120,038     60,942      

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 15—Transactions with Affiliates (Continued)

        Receivables from affiliates consist of the following:

 
  March 31,  
 
  2014   2013  
 
  (in thousands)
 

Receivables from entities affiliated with management

  $ 142   $ 22,883  

Receivables from SemGroup

    7,303      
           

  $ 7,445   $ 22,883  
           
           

        Payables to affiliates consist of the following:

 
  March 31,  
 
  2014   2013  
 
  (in thousands)
 

Payables to SemGroup

  $ 76,192   $ 4,601  

Payables to entities affiliated with management

    654     2,299  
           

  $ 76,846   $ 6,900  
           
           

        We completed a merger with High Sierra Energy, LP and High Sierra Energy GP, LLC in June 2012. We paid $91.8 million of cash, net of $5.0 million of cash acquired, and issued 18,018,468 common units to acquire High Sierra Energy, LP. We also paid $97.4 million of High Sierra Energy, LP's long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our general partner.

        During the year ended March 31, 2014, we completed the acquisition of a crude oil logistics business owned by an employee. We paid $11.0 million of cash for this acquisition. During the year ended March 31, 2013, we completed two business combinations with entities in which members of our management owned interests. We paid $14.0 million of cash (net of cash acquired) on a combined basis for these two acquisitions. We also paid $5.0 million under a non-compete agreement to an employee.

Note 16—Quarterly Financial Data (Unaudited)

        Our summarized unaudited quarterly financial data is presented below. The computation of net income per common and subordinated unit is done separately by quarter and year. The total of net income per common and subordinated unit of the individual quarters may not equal the net income per common and subordinated unit for the year, due primarily to the income allocation between the general partner and limited partners and variations in the weighted average units outstanding used in computing such amounts.

        Our retail propane segment's business is seasonal due to weather conditions in our service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either net losses or lower

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 16—Quarterly Financial Data (Unaudited) (Continued)

net income during the period from April through September of each year. Our liquids segment is also subject to seasonal fluctuations, as demand for propane and butane is typically higher during the winter months. Our operating revenues from our other segments are less weather sensitive. Additionally, the acquisitions described in Note 4 impact the comparability of the quarterly information within the year, and year to year.

 
  Quarter Ended    
 
 
  June 30,
2013
  September 30,
2013
  December 31,
2013
  March 31,
2014
  Year Ended
March 31,
2014
 
 
  (in thousands, except unit and per unit data)
 

Total revenues

  $ 1,385,957   $ 1,593,937   $ 2,743,445   $ 3,975,935   $ 9,699,274  

Total cost of sales

  $ 1,303,076   $ 1,488,850   $ 2,576,029   $ 3,764,744   $ 9,132,699  

Net income (loss)

  $ (17,508 ) $ (932 ) $ 24,052   $ 43,146   $ 48,758  

Net income (loss) attributable to parent equity

  $ (17,633 ) $ (941 ) $ 23,898   $ 42,331   $ 47,655  

Earnings (loss) per unit, basic and diluted—

                               

Common units

  $ (0.35 ) $ (0.05 ) $ 0.27   $ 0.46   $ 0.51  

Subordinated units

  $ (0.46 ) $ (0.09 ) $ 0.23   $ 0.46   $ 0.32  

Weighted average common units outstanding—basic and diluted

    47,703,313     58,909,389     67,941,726     73,421,309     61,970,471  

Weighted average subordinated outstanding units—basic and diluted

    5,919,346     5,919,346     5,919,346     5,919,346     5,919,346  

 

 
  Quarter Ended    
 
 
  June 30,
2012
  September 30,
2012
  December 31,
2012
  March 31,
2013
  Year Ended
March 31,
2013
 
 
  (in thousands, except unit and per unit data)
 

Total revenues

  $ 326,436   $ 1,135,510   $ 1,338,208   $ 1,617,613   $ 4,417,767  

Total cost of sales

  $ 298,985   $ 1,053,690   $ 1,204,545   $ 1,481,890   $ 4,039,110  

Net income (loss)

  $ (24,710 ) $ 10,082   $ 40,477   $ 22,341   $ 48,190  

Net income (loss) attributable to parent equity

  $ (24,650 ) $ 10,073   $ 40,176   $ 22,341   $ 47,940  

Earnings (loss) per unit, basic and diluted—

                               

Common units

  $ (0.76 ) $ 0.18   $ 0.75   $ 0.39   $ 0.96  

Subordinated units

  $ (0.77 ) $ 0.18   $ 0.75   $ 0.39   $ 0.93  

Weighted average common units outstanding—basic and diluted

    26,529,133     44,831,836     46,364,381     47,665,015     41,353,574  

Weighted average subordinated outstanding units—basic and diluted

    5,919,346     5,919,346     5,919,346     5,919,346     5,919,346  

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information

        Certain of our wholly-owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the Unsecured Notes (described in Note 8). Pursuant to Rule 3-10 of Regulation S-X, we have presented in columnar format the condensed consolidating financial information for NGL Energy Partners LP, NGL Energy Finance Corp. (which, along with NGL Energy Partners LP, is a co-issuer of the Unsecured Notes), the guarantor subsidiaries on a combined basis, and the non-guarantor subsidiaries on a combined basis in the tables below.

        During the periods presented in the tables below, the status of certain subsidiaries changed, in that they either became guarantors of or ceased to be guarantors of the Unsecured Notes. Such changes have been given retrospective application in the tables below.

        There are no significant restrictions upon the ability of the parent or any of the guarantor subsidiaries to obtain funds from their respective subsidiaries by dividend or loan. None of the assets of the guarantor subsidiaries represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.

        For purposes of the tables below, (i) the condensed consolidating financial information is presented on a legal entity basis, not a business segment basis, (ii) investments in consolidated subsidiaries are accounted for as equity method investments, and (iii) contributions, distributions, and advances to or from consolidated entities are reported on a net basis within net changes in advances with consolidated entities in the condensed consolidating cash flow tables below.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Balance Sheet
(U.S. Dollars in Thousands)

 
  March 31, 2014  
 
  NGL Energy
Partners LP
(Parent)(1)
  NGL Energy
Finance Corp.
  Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

ASSETS

                                     

CURRENT ASSETS:

                                     

Cash and cash equivalents

  $ 1,181   $   $ 8,728   $ 531   $   $ 10,440  

Accounts receivable—trade, net of allowance for doubtful accounts

            887,789     13,115         900,904  

Accounts receivable—affiliates

            7,445             7,445  

Inventories

            306,434     3,726         310,160  

Prepaid expenses and other current assets

            80,294     56         80,350  
                           

Total current assets

    1,181         1,290,690     17,428         1,309,299  

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation

   
   
   
764,014
   
65,332
   
   
829,346
 

GOODWILL

            1,105,008     1,998         1,107,006  

INTANGIBLE ASSETS, net of accumulated amortization

    1,169     11,552     700,603     1,632         714,956  

INVESTMENTS IN UNCONSOLIDATED ENTITIES

            189,821             189,821  

NET INTERCOMPANY RECEIVABLES (PAYABLES)

    327,281     437,714     (720,737 )   (44,258 )        

INVESTMENTS IN CONSOLIDATED SUBSIDIARIES

    1,447,502         17,673         (1,465,175 )    

OTHER NONCURRENT ASSETS

            16,674     121         16,795  
                           

Total assets

  $ 1,777,133   $ 449,266   $ 3,363,746   $ 42,253   $ (1,465,175 ) $ 4,167,223  
                           
                           

LIABILITIES AND EQUITY

                                     

CURRENT LIABILITIES:

                                     

Accounts payable—trade

  $   $   $ 726,252   $ 13,959   $   $ 740,211  

Accounts payable—affiliates

            73,703     3,143         76,846  

Accrued expenses and other payables

    554     14,266     124,923     1,947         141,690  

Advance payments received from customers

            29,891     74         29,965  

Current maturities of long-term debt

            7,058     22         7,080  
                           

Total current liabilities

    554     14,266     961,827     19,145         995,792  

LONG-TERM DEBT, net of current maturities

    250,000     450,000     929,754     80         1,629,834  

OTHER NONCURRENT LIABILITIES

            9,663     81         9,744  

EQUITY

                                     

Partners' equity (deficit)

    1,526,579     (15,000 )   1,462,691     22,994     (1,470,449 )   1,526,815  

Accumulated other comprehensive loss

            (189 )   (47 )       (236 )

Noncontrolling interests

                    5,274     5,274  
                           

Total equity (deficit)

    1,526,579     (15,000 )   1,462,502     22,947     (1,465,175 )   1,531,853  
                           

Total liabilities and equity

  $ 1,777,133   $ 449,266   $ 3,363,746   $ 42,253   $ (1,465,175 ) $ 4,167,223  
                           
                           

(1)
The parent is a co-issuer of the $450.0 million 6.875% Unsecured Notes that are included in the NGL Energy Finance Corp. column.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Balance Sheet
(U.S. Dollars in Thousands)

 
  March 31, 2013  
 
  NGL Energy
Partners LP
(Parent)
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

ASSETS

                               

CURRENT ASSETS:

                               

Cash and cash equivalents

  $   $ 11,206   $ 355   $   $ 11,561  

Accounts receivable—trade, net of allowance for doubtful accounts

        561,560     1,197         562,757  

Accounts receivable—affiliates

        22,883             22,883  

Inventories

        126,024     871         126,895  

Prepaid expenses and other current assets

        37,784     107         37,891  
                       

Total current assets

        759,457     2,530         761,987  

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation

   
   
497,743
   
28,694
   
   
526,437
 

GOODWILL

        553,222     1,998         555,220  

INTANGIBLE ASSETS, net of accumulated amortization

    717     439,365     1,350         441,432  

NET INTERCOMPANY RECEIVABLES (PAYABLES)

    237,736     (233,294 )   (4,442 )        

INVESTMENTS IN CONSOLIDATED SUBSIDIARIES

    895,779     20,371         (916,150 )    

OTHER NONCURRENT ASSETS

        6,542             6,542  
                       

Total assets

  $ 1,134,232   $ 2,043,406   $ 30,130   $ (916,150 ) $ 2,291,618  
                       
                       

LIABILITIES AND EQUITY

                               

CURRENT LIABILITIES:

                               

Accounts payable—trade

  $   $ 534,164   $ 1,891   $   $ 536,055  

Accounts payable—affiliates

        6,900             6,900  

Accrued expenses and other payables

    554     83,001     2,051         85,606  

Advance payments received from customers                 

        22,364     8         22,372  

Current maturities of long-term debt

        8,610     16         8,626  
                       

Total current liabilities

    554     655,039     3,966         659,559  

LONG-TERM DEBT, net of current maturities

   
250,000
   
490,433
   
3
   
   
740,436
 

OTHER NONCURRENT LIABILITIES

        2,155     50         2,205  

EQUITY

                               

Partners' equity

    883,678     895,779     26,087     (921,890 )   883,654  

Accumulated other comprehensive income           

            24         24  

Noncontrolling interests

                5,740     5,740  
                       

Total equity

    883,678     895,779     26,111     (916,150 )   889,418  
                       

Total liabilities and equity

  $ 1,134,232   $ 2,043,406   $ 30,130   $ (916,150 ) $ 2,291,618  
                       
                       

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Operations
(U.S. Dollars in Thousands)

 
  Year Ended March 31, 2014  
 
  NGL Energy
Partners LP
(Parent)(1)
  NGL Energy
Finance Corp.
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

REVENUES

  $   $   $ 9,560,124   $ 139,519   $ (369 ) $ 9,699,274  

COST OF SALES

            9,011,011     122,057     (369 )   9,132,699  

OPERATING COSTS AND EXPENSES:

                                     

Operating

            253,214     6,182         259,396  

General and administrative

            77,756     2,104         79,860  

Depreciation and amortization

            117,573     3,181         120,754  
                           

Operating Income

            100,570     5,995         106,565  

OTHER INCOME (EXPENSE):

                                     

Earnings from unconsolidated entities

            1,898             1,898  

Interest expense

    (16,818 )   (15,000 )   (27,031 )   (51 )   46     (58,854 )

Other, net

            202     (70 )   (46 )   86  
                           

Income (Loss) Before Income Taxes

    (16,818 )   (15,000 )   75,639     5,874         49,695  

INCOME TAX PROVISION

            (937 )           (937 )

EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES

    64,473         4,771         (69,244 )    
                           

Net Income (Loss)

    47,655     (15,000 )   79,473     5,874     (69,244 )   48,758  

NET INCOME ALLOCATED TO GENERAL PARTNER

                            (14,148 )   (14,148 )

NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

                            (1,103 )   (1,103 )
                           

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS

  $ 47,655   $ (15,000 ) $ 79,473   $ 5,874   $ (84,495 ) $ 33,507  
                           
                           

(1)
The parent is a co-issuer of the $450.0 million 6.875% Unsecured Notes that are included in the NGL Energy Finance Corp. column.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Operations
(U.S. Dollars in Thousands)

 
  Year Ended March 31, 2013  
 
  NGL Energy
Partners LP
(Parent)
  Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

REVENUES

  $   $ 4,409,198   $ 8,878   $ (309 ) $ 4,417,767  

COST OF SALES

   
   
4,038,251
   
1,168
   
(309

)
 
4,039,110
 

OPERATING COSTS AND EXPENSES:

   
 
   
 
   
 
   
 
   
 
 

Operating

        164,944     4,855         169,799  

General and administrative

        52,461     237         52,698  

Depreciation and amortization

        66,916     1,937         68,853  
                       

Operating Income

        86,626     681         87,307  

OTHER INCOME (EXPENSE):

   
 
   
 
   
 
   
 
   
 
 

Interest expense

    (13,041 )   (19,951 )   (48 )   46     (32,994 )

Loss on early extinguishment of debt

        (5,769 )           (5,769 )

Other, net

        1,666     (99 )   (46 )   1,521  
                       

Income (Loss) Before Income Taxes

    (13,041 )   62,572     534         50,065  

INCOME TAX PROVISION

   
   
(1,875

)
 
   
   
(1,875

)

EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES

   
60,981
   
284
   
   
(61,265

)
 
 
                       

Net Income

    47,940     60,981     534     (61,265 )   48,190  

NET INCOME ALLOCATED TO GENERAL PARTNER

                     
(2,917

)
 
(2,917

)

NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

                     
(250

)
 
(250

)
                       

NET INCOME ALLOCATED TO LIMITED PARTNERS

  $ 47,940   $ 60,981   $ 534   $ (64,432 ) $ 45,023  
                       
                       

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Operations
(U.S. Dollars in Thousands)

 
  Year Ended March 31, 2012  
 
  NGL Energy
Partners LP
(Parent)
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

REVENUES

  $   $ 1,310,473   $ 225   $ (225 ) $ 1,310,473  

COST OF SALES

   
   
1,217,248
   
   
(225

)
 
1,217,023
 

OPERATING COSTS AND EXPENSES:

   
 
   
 
   
 
   
 
   
 
 

Operating

        47,162     138         47,300  

General and administrative

        15,823     186         16,009  

Depreciation and amortization

        14,964     147         15,111  
                       

Operating Income (Loss)

        15,276     (246 )       15,030  

OTHER INCOME (EXPENSE):

   
 
   
 
   
 
   
 
   
 
 

Interest expense

        (7,619 )   (46 )   45     (7,620 )

Other, net

        1,100         (45 )   1,055  
                       

Income (Loss) Before Income Taxes

        8,757     (292 )       8,465  

INCOME TAX PROVISION

   
   
(601

)
 
   
   
(601

)

EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES

   
7,876
   
(280

)
 
   
(7,596

)
 
 
                       

Net Income (Loss)

    7,876     7,876     (292 )   (7,596 )   7,864  

NET INCOME ALLOCATED TO GENERAL PARTNER

                     
(8

)
 
(8

)

NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS

                     
12
   
12
 
                       

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS

  $ 7,876   $ 7,876   $ (292 ) $ (7,592 ) $ 7,868  
                       
                       

F-75


Table of Contents


NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Comprehensive Income (Loss)
(U.S. Dollars in Thousands)

 
  Year Ended March 31, 2014  
 
  NGL Energy
Partners LP
(Parent)(1)
  NGL Energy
Finance Corp.
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

Net income (loss)

  $ 47,655   $ (15,000 ) $ 79,473   $ 5,874   $ (69,244 ) $ 48,758  

Other comprehensive loss, net of tax

            (189 )   (71 )       (260 )
                           

Comprehensive income (loss)

  $ 47,655   $ (15,000 ) $ 79,284   $ 5,803   $ (69,244 ) $ 48,498  
                           
                           

(1)
The parent is a co-issuer of the $450.0 million 6.875% Unsecured Notes that are included in the NGL Energy Finance Corp. column.

 
  Year Ended March 31, 2013  
 
  NGL Energy
Partners LP
(Parent)
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

Net income

  $ 47,940   $ 60,981   $ 534   $ (61,265 ) $ 48,190  

Other comprehensive loss, net of tax

            (7 )       (7 )
                       

Comprehensive income

  $ 47,940   $ 60,981   $ 527   $ (61,265 ) $ 48,183  
                       
                       

 

 
  Year Ended March 31, 2012  
 
  NGL Energy
Partners LP
(Parent)
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

Net income (loss)

  $ 7,876   $ 7,876   $ (292 ) $ (7,596 ) $ 7,864  

Other comprehensive loss, net of tax

            (25 )       (25 )
                       

Comprehensive income (loss)

  $ 7,876   $ 7,876   $ (317 ) $ (7,596 ) $ 7,839  
                       
                       

F-76


Table of Contents


NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Cash Flows
(U.S. Dollars in Thousands)

 
  Year Ended March 31, 2014  
 
  NGL Energy
Partners LP
(Parent)(1)
  NGL Energy
Finance Corp.
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidated  

OPERATING ACTIVITIES:

                               

Net cash provided by (used in) operating activities           

  $ (16,625 ) $   $ 99,754   $ 2,107   $ 85,236  

INVESTING ACTIVITIES:

   
 
   
 
   
 
   
 
   
 
 

Purchases of long-lived assets

            (118,455 )   (46,693 )   (165,148 )

Acquisitions of businesses, including acquired working capital, net of cash acquired

    (334,154 )       (932,373 )   (2,283 )   (1,268,810 )

Cash flows from commodity derivatives

            (35,956 )       (35,956 )

Proceeds from sales of assets

            12,884     11,776     24,660  

Investments in unconsolidated entities

            (11,515 )       (11,515 )

Distributions of capital from unconsolidated entities

            1,591         1,591  

Other

            540     (735 )   (195 )
                       

Net cash used in investing activities

    (334,154 )       (1,083,284 )   (37,935 )   (1,455,373 )
                       

FINANCING ACTIVITIES:

                               

Proceeds from borrowings under revolving credit facilities

            2,545,500         2,545,500  

Payments on revolving credit facilities

            (2,101,000 )       (2,101,000 )

Issuances of notes

        450,000             450,000  

Proceeds from borrowings on other long-term debt

            780     100     880  

Payments on other long-term debt

            (8,802 )   (17 )   (8,819 )

Debt issuance costs

    (645 )   (12,286 )   (11,664 )       (24,595 )

Contributions

    765             2,060     2,825  

Distributions

    (145,090 )           (840 )   (145,930 )

Proceeds from sale of common units, net of offering costs

    650,155                 650,155  

Net changes in advances with consolidated entities

    (153,225 )   (437,714 )   556,238     34,701      
                       

Net cash provided by financing activities        

    351,960         981,052     36,004     1,369,016  
                       

Net increase (decrease) in cash and cash equivalents           

    1,181         (2,478 )   176     (1,121 )

Cash and cash equivalents, beginning of period

            11,206     355     11,561  
                       

Cash and cash equivalents, end of period

  $ 1,181   $   $ 8,728   $ 531   $ 10,440  
                       
                       

(1)
The parent is a co-issuer of the $450.0 million 6.875% Unsecured Notes that are included in the NGL Energy Finance Corp. column.

F-77


Table of Contents


NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Cash Flows
(U.S. Dollars in Thousands)

 
  Year Ended March 31, 2013  
 
  NGL Energy
Partners LP
(Parent)
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidated  

OPERATING ACTIVITIES:

                         

Net cash provided by (used in) operating activities

  $ (12,428 ) $ 140,794   $ 4,268   $ 132,634  

INVESTING ACTIVITIES:

   
 
   
 
   
 
   
 
 

Purchases of long-lived assets

        (59,903 )   (12,572 )   (72,475 )

Acquisitions of businesses, including acquired working capital, net of cash acquired

    (452,087 )   (38,718 )       (490,805 )

Cash flows from commodity derivatives

        11,579         11,579  

Proceeds from sales of assets

        5,080         5,080  
                   

Net cash used in investing activities

    (452,087 )   (81,962 )   (12,572 )   (546,621 )
                   

FINANCING ACTIVITIES:

                         

Proceeds from borrowings under revolving credit facilities

        1,227,975         1,227,975  

Payments on revolving credit facilities

        (964,475 )       (964,475 )

Issuance of notes

    250,000             250,000  

Proceeds from borrowings on other long-term debt

        634     19     653  

Payments on other long-term debt

        (4,837 )       (4,837 )

Debt issuance costs

    (777 )   (19,412 )       (20,189 )

Contributions

    510         403     913  

Distributions

    (71,608 )       (74 )   (71,682 )

Proceeds from sale of common units, net of offering costs

    (642 )           (642 )

Net changes in advances with consolidated entities

    286,991     (295,105 )   8,114      
                   

Net cash provided by (used in) financing activities

    464,474     (55,220 )   8,462     417,716  
                   

Net increase (decrease) in cash and cash equivalents

    (41 )   3,612     158     3,729  

Cash and cash equivalents, beginning of period

    41     7,594     197     7,832  
                   

Cash and cash equivalents, end of period

  $   $ 11,206   $ 355   $ 11,561  
                   
                   

F-78


Table of Contents


NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Cash Flows
(U.S. Dollars in Thousands)

 
  Year Ended March 31, 2012  
 
  NGL Energy
Partners LP
(Parent)
  Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidated  

OPERATING ACTIVITIES:

                         

Net cash provided by (used in) operating activities

  $   $ 90,477   $ (148 ) $ 90,329  

INVESTING ACTIVITIES:

   
 
   
 
   
 
   
 
 

Purchases of long-lived assets

        (6,667 )   (877 )   (7,544 )

Acquisitions of businesses, including acquired working capital, net of cash acquired

    (291,097 )   (6,304 )       (297,401 )

Cash flows from commodity derivatives

        6,464         6,464  

Proceeds from sales of assets

        1,238         1,238  

Other

        346         346  
                   

Net cash used in investing activities        

    (291,097 )   (4,923 )   (877 )   (296,897 )
                   

FINANCING ACTIVITIES:

                         

Proceeds from borrowings under revolving credit facilities

        478,900         478,900  

Payments on revolving credit facilities

        (329,900 )       (329,900 )

Payments on other long-term debt

        (1,278 )       (1,278 )

Debt issuance costs

        (2,380 )       (2,380 )

Contributions

            440     440  

Distributions

    (19,060 )           (19,060 )

Proceeds from sale of common units, net of offering costs

    74,759             74,759  

Repurchase of common units

    (3,418 )           (3,418 )

Net changes in advances with consolidated entities

    238,816     (239,476 )   660      
                   

Net cash provided by (used in) financing activities

    291,097     (94,134 )   1,100     198,063  
                   

Net increase (decrease) in cash and cash equivalents

        (8,580 )   75     (8,505 )

Cash and cash equivalents, beginning of period

    41     16,174     122     16,337  
                   

Cash and cash equivalents, end of period

  $ 41   $ 7,594   $ 197   $ 7,832  
                   
                   

F-79


Table of Contents


NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Balance Sheets

(U.S. Dollars in Thousands, except unit amounts)

 
  September 30,
2014
  March 31,
2014
 

ASSETS

             

CURRENT ASSETS:

             

Cash and cash equivalents

  $ 11,823   $ 10,440  

Accounts receivable—trade, net of allowance for doubtful accounts of $2,816 and $2,822, respectively

    1,433,117     900,904  

Accounts receivable—affiliates

    41,706     7,445  

Inventories

    941,589     310,160  

Prepaid expenses and other current assets

    156,818     80,350  
           

Total current assets

    2,585,053     1,309,299  

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $153,057 and $109,564, respectively

   
1,433,313
   
829,346
 

GOODWILL

    1,170,490     1,107,006  

INTANGIBLE ASSETS, net of accumulated amortization of $166,484 and $116,728, respectively

    838,088     714,956  

INVESTMENTS IN UNCONSOLIDATED ENTITIES

    482,644     189,821  

OTHER NONCURRENT ASSETS

    42,091     16,795  
           

Total assets

  $ 6,551,679   $ 4,167,223  
           
           

LIABILITIES AND EQUITY

             

CURRENT LIABILITIES:

             

Accounts payable—trade

  $ 1,345,024   $ 740,211  

Accounts payable—affiliates

    85,307     76,846  

Accrued expenses and other payables

    218,482     141,690  

Advance payments received from customers

    106,105     29,965  

Current maturities of long-term debt

    5,062     7,080  
           

Total current liabilities

    1,759,980     995,792  

LONG-TERM DEBT, net of current maturities

   
2,437,351
   
1,629,834
 

OTHER NONCURRENT LIABILITIES

    39,518     9,744  

COMMITMENTS AND CONTINGENCIES

   
 
   
 
 

EQUITY, per accompanying statement:

   
 
   
 
 

General partner, representing a 0.1% interest, 88,634 and 79,420 notional units at September 30, 2014 and March 31, 2014, respectively

    (39,690 )   (45,287 )

Limited partners, representing a 99.9% interest—

             

Common units, 88,545,764 and 73,421,309 units issued and outstanding at September 30, 2014 and March 31, 2014, respectively

    1,785,823     1,570,074  

Subordinated units, 5,919,346 units issued and outstanding at March 31, 2014                

        2,028  

Accumulated other comprehensive loss

    (73 )   (236 )

Noncontrolling interests

    568,770     5,274  
           

Total equity

    2,314,830     1,531,853  
           

Total liabilities and equity

  $ 6,551,679   $ 4,167,223  
           
           

   

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-80


Table of Contents


NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Operations

Three Months and Six Months Ended September 30, 2014 and 2013

(U.S. Dollars in Thousands, except unit and per unit amounts)

 
  Three Months Ended
September 30,
  Six Months Ended
September 30,
 
 
  2014   2013   2014   2013  

REVENUES:

                         

Crude oil logistics

  $ 2,111,143   $ 1,014,008   $ 4,040,426   $ 1,944,802  

Water solutions

    52,719     34,190     100,033     54,703  

Liquids

    539,753     484,874     1,014,910     845,833  

Retail propane

    68,358     59,380     146,260     131,597  

Refined products and renewables

    2,607,220         3,724,717      

Other

    1,333     1,485     2,794     2,959  
                   

Total Revenues

    5,380,526     1,593,937     9,029,140     2,979,894  
                   

COST OF SALES:

                         

Crude oil logistics

    2,083,712     992,135     3,981,351     1,901,354  

Water solutions

    (9,439 )   3,782     1,134     4,365  

Liquids

    514,064     459,394     976,080     809,645  

Retail propane

    39,894     33,539     87,418     76,562  

Refined products and renewables

    2,550,851         3,665,164      

Other

    383         2,371      
                   

Total Cost of Sales

    5,179,465     1,488,850     8,713,518     2,791,926  
                   

OPERATING COSTS AND EXPENSES:

                         

Operating

    101,553     55,769     169,421     104,814  

General and administrative

    41,639     14,312     69,512     32,766  

Depreciation and amortization

    50,099     25,061     89,474     47,785  
                   

Operating Income (Loss)

    7,770     9,945     (12,785 )   2,603  

OTHER INCOME (EXPENSE):

   
 
   
 
   
 
   
 
 

Earnings of unconsolidated entities

    3,697         6,262      

Interest expense

    (28,651 )   (11,060 )   (49,145 )   (21,682 )

Other, net

    (617 )   419     (1,008 )   469  
                   

Loss Before Income Taxes

    (17,801 )   (696 )   (56,676 )   (18,610 )

INCOME TAX (PROVISION) BENEFIT

   
1,922
   
(236

)
 
887
   
170
 
                   

Net Loss

    (15,879 )   (932 )   (55,789 )   (18,440 )

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER

   
(11,056

)
 
(2,451

)
 
(20,437

)
 
(4,139

)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

   
(3,345

)
 
(9

)
 
(3,410

)
 
(134

)
                   

NET LOSS ALLOCATED TO LIMITED PARTNERS

  $ (30,280 ) $ (3,392 ) $ (79,636 ) $ (22,713 )
                   
                   

BASIC AND DILUTED LOSS PER COMMON UNIT

  $ (0.34 ) $ (0.05 ) $ (0.93 ) $ (0.37 )
                   
                   

BASIC AND DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING

    88,331,653     58,909,389     81,267,742     53,336,969  
                   
                   

   

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-81


Table of Contents


NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Comprehensive Loss

Three Months and Six Months Ended September 30, 2014 and 2013

(U.S. Dollars in Thousands)

 
  Three Months
Ended September 30,
  Six Months Ended September 30,  
 
  2014   2013   2014   2013  

Net loss

  $ (15,879 ) $ (932 ) $ (55,789 ) $ (18,440 )

Other comprehensive income (loss)

    (22 )   (5 )   163     (30 )
                   

Comprehensive loss

  $ (15,901 ) $ (937 ) $ (55,626 ) $ (18,470 )
                   
                   

   

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-82


Table of Contents


NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statement of Changes in Equity

(U.S. Dollars in Thousands, except unit amounts)

 
   
  Limited Partners    
   
   
 
 
   
  Accumulated
Other
Comprehensive
Loss
   
   
 
 
  General
Partner
  Common
Units
  Amount   Subordinated
Units
  Amount   Noncontrolling
Interests
  Total
Equity
 

BALANCES AT MARCH 31, 2014

  $ (45,287 )   73,421,309   $ 1,570,074     5,919,346   $ 2,028   $ (236 ) $ 5,274   $ 1,531,853  

Distributions

    (15,235 )       (89,025 )       (6,748 )       (8,654 )   (119,662 )

Contributions

    395                             395  

Sales of units, net of issuance costs

        8,767,100     370,446                     370,446  

Conversion of subordinated units to common units

        5,919,346     (8,733 )   (5,919,346 )   8,733              

Equity issued pursuant to incentive compensation plan

        438,009     18,684                     18,684  

Business combinations

                            568,740     568,740  

Net income (loss)

    20,437         (75,623 )       (4,013 )       3,410     (55,789 )

Other comprehensive income

                        163         163  
                                   

BALANCES AT SEPTEMBER 30, 2014

  $ (39,690 )   88,545,764   $ 1,785,823       $   $ (73 ) $ 568,770   $ 2,314,830  
                                   
                                   

   

The accompanying notes are an integral part of these condensed consolidated financial statements.

F-83


Table of Contents


NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Cash Flows

(U.S. Dollars in Thousands)

 
  Six Months Ended
September 30,
 
 
  2014   2013  

OPERATING ACTIVITIES:

             

Net loss

  $ (55,789 ) $ (18,440 )

Adjustments to reconcile net loss to net cash used in operating activities:

             

Depreciation and amortization, including debt issuance cost amortization

    97,624     51,821  

Non-cash equity-based compensation expense

    11,758     6,762  

Loss on disposal or impairment of assets

    4,566     2,163  

Provision for doubtful accounts

    1,347     781  

Commodity derivative (gain) loss

    (38,496 )   17,881  

Earnings of unconsolidated entities

    (6,262 )    

Distributions from unconsolidated entities

    5,180      

Other

    (837 )   8  

Changes in operating assets and liabilities, exclusive of acquisitions:

             

Accounts receivable—trade

    (358,497 )   (28,013 )

Accounts receivable—affiliates

    (33,733 )   19,812  

Inventories

    (203,965 )   (226,727 )

Prepaid expenses and other assets

    (56,109 )   (10,830 )

Accounts payable—trade

    463,767     60,725  

Accounts payable—affiliates

    8,392     11,529  

Accrued expenses and other liabilities

    25,719     18,162  

Advance payments received from customers

    73,700     45,622  
           

Net cash used in operating activities

    (61,635 )   (48,744 )
           

INVESTING ACTIVITIES:

             

Purchases of long-lived assets

    (82,851 )   (67,399 )

Acquisitions of businesses, including acquired working capital, net of cash acquired

    (658,764 )   (392,605 )

Cash flows from commodity derivatives

    4,327     (19,074 )

Proceeds from sales of assets

    8,741     2,224  

Investments in unconsolidated entities

    (26,390 )    

Distributions of capital from unconsolidated entities

    4,649      
           

Net cash used in investing activities

    (750,288 )   (476,854 )
           

FINANCING ACTIVITIES:

             

Proceeds from borrowings under revolving credit facilities

    1,979,500     1,061,500  

Payments on revolving credit facilities

    (1,804,000 )   (893,000 )

Issuance of notes

    400,000      

Proceeds from borrowings on other long-term debt

        880  

Payments on other long-term debt

    (4,175 )   (4,507 )

Debt issuance costs

    (9,198 )   (2,218 )

Contributions

    395     2,444  

Distributions to owners

    (111,008 )   (60,623 )

Distributions to noncontrolling interest partners

    (8,654 )    

Proceeds from sale of common units, net of offering costs

    370,446     415,089  
           

Net cash provided by financing activities

    813,306     519,565  
           

Net increase (decrease) in cash and cash equivalents

    1,383     (6,033 )

Cash and cash equivalents, beginning of period

    10,440     11,561  
           

Cash and cash equivalents, end of period

  $ 11,823   $ 5,528  
           
           

   

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 1—Organization and Operations

        NGL Energy Partners LP ("we," "us," "our," or the "Partnership") is a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At September 30, 2014, our operations include:

Note 2—Significant Accounting Policies

Basis of Presentation

        The unaudited condensed consolidated financial statements as of and for the three months and six months ended September 30, 2014 and 2013 include our accounts and those of our controlled subsidiaries. Investments where we do not have the ability to exercise control, but do have the ability to exercise significant influence, are accounted for using the equity method of accounting. All significant intercompany transactions and account balances have been eliminated in consolidation. The unaudited condensed consolidated balance sheet at March 31, 2014 is derived from audited financial statements. We have made certain reclassifications to prior period financial statements to conform to classification

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 2—Significant Accounting Policies (Continued)

methods used in fiscal year 2015. These reclassifications had no impact on previously reported amounts of equity or net income.

        The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") for interim consolidated financial information in accordance with the rules and regulations of the Securities and Exchange Commission. The unaudited condensed consolidated financial statements include all adjustments that we consider necessary for a fair presentation of our consolidated financial position and results of operations for the interim periods presented. Such adjustments consist of only normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed consolidated financial statements do not include all the information and notes required by GAAP for complete annual consolidated financial statements. However, we believe that the disclosures made are adequate to make the information not misleading. These interim unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements for the fiscal year ended March 31, 2014 included in elsewhere in this prospectus. Due to the seasonal nature of our natural gas liquids operations and other factors, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Use of Estimates

        The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amount of revenues and expenses during the period. Actual results could differ from those estimates.

Significant Accounting Policies

        Our significant accounting policies are consistent with those disclosed in Note 2 of our audited consolidated financial statements included elsewhere in this prospectus.

Revenue Recognition

        We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. We record terminaling, transportation, storage, and service revenues at the time the service is performed, and we record tank and other rentals over the term of the lease. Pursuant to terminaling services agreements with certain of our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Such measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the product gained. Revenues for our water solutions business are recognized upon receipt of the wastewater at our disposal facilities.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 2—Significant Accounting Policies (Continued)

        We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. Amounts billed to customers for shipping and handling costs are included in revenues in our condensed consolidated statements of operations.

        We enter into certain contracts whereby we agree to purchase product from a counterparty and sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into concurrently and are entered into in contemplation of each other, we record the revenues for these transactions net of cost of sales.

Fair Value Measurements

        We apply fair value measurements to certain assets and liabilities, principally our commodity derivative instruments and assets and liabilities acquired in business combinations. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

        We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 2—Significant Accounting Policies (Continued)

        The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability.

Supplemental Cash Flow Information

        Supplemental cash flow information is as follows:

 
  Three Months Ended
September 30,
  Six Months Ended
September 30,
 
 
  2014   2013   2014   2013  
 
  (in thousands)
 

Interest paid, exclusive of debt issuance costs and letter of credit fees

  $ 10,445   $ 8,423   $ $36,429   $ 16,908  
                   
                   

Income taxes paid

  $ 1,241   $ 369   $ 2,246   $ 650  
                   
                   

Value of common units issued in business combinations

  $   $ 80,619   $   $ 80,619  
                   
                   

        Cash flows from settlements of commodity derivative instruments are classified as cash flows from investing activities in the condensed consolidated statements of cash flows, and adjustments to the fair value of commodity derivative instruments are included in the reconciliation of net loss to net cash used in operating activities.

Inventories

        We value our inventories at the lower of cost or market, with cost determined using either the weighted-average cost or the first in, first out (FIFO) methods, including the cost of transportation and storage. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business for sale in the retail markets.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 2—Significant Accounting Policies (Continued)

        Inventories consist of the following:

 
  September 30,
2014
  March 31,
2014
 
 
  (in thousands)
 

Crude oil

  $ 136,722   $ 156,473  

Natural gas liquids—

             

Propane

    207,694     85,159  

Butane

    84,822     15,106  

Other

    27,091     3,945  

Refined products—

             

Gasoline

    219,111     15,597  

Diesel

    214,567     7,298  

Other

    3,675     314  

Renewables

    36,517     11,778  

Other

    11,390     14,490  
           

Total

  $ 941,589   $ 310,160  
           
           

Investments in Unconsolidated Entities

        In December 2013, as part of our acquisition of Gavilon, LLC ("Gavilon Energy"), we acquired a 50% interest in Glass Mountain Pipeline, LLC ("Glass Mountain") and an 11% interest in a limited liability company that owns an ethanol production facility. In June 2014, we acquired an interest in a limited liability company that operates a water supply business. On July 1, 2014, as part of our acquisition of TransMontaigne Inc. ("TransMontaigne"), we acquired TLP, which owns a 42.5% interest in BOSTCO and a 50% interest in Frontera. We account for these investments using the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on our condensed consolidated balance sheets; instead, our ownership interests are reported within investments in unconsolidated entities on our condensed consolidated balance sheets. Under the equity method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions paid and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the book value of the net assets of the investment entity.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 2—Significant Accounting Policies (Continued)

        Our investments in unconsolidated entities consist of the following:

 
  September 30,
2014
  March 31,
2014
 
 
  (in thousands)
 

Glass Mountain(1)

  $ 189,847   $ 181,488  

Ethanol production facility

    9,361     8,333  

Water supply company

    15,026      

BOSTCO(2)

    244,092      

Frontera

    24,318      
           

Total

  $ 482,644   $ 189,821  
           
           

(1)
When we acquired Gavilon we recorded the investment in Glass Mountain at fair value. The fair value of our investment in Glass Mountain exceeds our share of the historical net book value of Glass Mountain's net assets by approximately $70 million. This difference relates primarily to goodwill and customer relationships.

(2)
When we acquired TransMontaigne, we recorded the investment in BOSTCO at fair value. The fair value of our investment in BOSTCO exceeds our share of the historical net book value of BOSTCO's net assets by approximately $24 million.

Accrued Expenses and Other Payables

        Accrued expenses and other payables consist of the following:

 
  September 30,
2014
  March 31,
2014
 
 
  (in thousands)
 

Accrued compensation and benefits

  $ 49,146   $ 45,006  

Derivative liabilities

    39,023     42,214  

Product exchange liabilities

    43,185     3,719  

Accrued interest

    23,945     18,668  

Income and other tax liabilities

    38,255     13,421  

Other

    24,928     18,662  
           

Total

  $ 218,482   $ 141,690  
           
           

Business Combination Measurement Period

        We record the assets acquired and liabilities assumed in a business combination at their acquisition-date fair values. Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination. As described in Note 4, certain of our acquisitions are still within this measurement period, and as a result, the acquisition-date fair values we have recorded for the assets acquired and liabilities assumed are subject to change. Also as

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 2—Significant Accounting Policies (Continued)

described in Note 4, we made certain adjustments during the six months ended September 30, 2014 to our estimates of the acquisition-date fair values of assets acquired and liabilities assumed in business combinations that occurred during the year ended March 31, 2014.

Noncontrolling Interests

        We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our condensed consolidated financial statements represents the other owners' share of these entities.

        On July 1, 2014, as part of our acquisition of TransMontaigne, we acquired a 19.7% limited partner interest in TLP. We have attributed net earnings allocable to TLP's limited partners to the controlling and noncontrolling interests based on the relative ownership interests in TLP as well as including certain adjustments related to our acquisition accounting. Net earnings allocable to TLP's limited partners are net of the earnings allocable to TLP's general partner interest. The earnings allocable to TLP's general partner interest include the distributions of available cash (as defined by TLP's partnership agreement) attributable to the period to TLP's general partner interest and incentive distribution rights, net of adjustments for TLP's general partner's share of undistributed earnings. Undistributed earnings are allocated to TLP's limited partners and TLP's general partner interest based on their respective sharing of earnings or losses specified in TLP's partnership agreement, which is based on their ownership percentages of 98% and 2%, respectively.

Note 3—Earnings Per Unit

        Our earnings per common unit were computed as follows:

 
  Three Months Ended
September 30,
  Six Months Ended
September 30,
 
 
  2014   2013   2014   2013  
 
  (in thousands, except unit and per unit amounts)
 

Net loss attributable to parent equity

  $ (19,224 ) $ (941 ) $ (59,199 ) $ (18,574 )

Less: net income allocated to general partner(1)

    (11,056 )   (2,451 )   (20,437 )   (4,139 )

Net loss allocated to subordinated unitholders(2)

        562     4,013     3,076  
                   

Net loss allocated to common unitholders

  $ (30,280 ) $ (2,830 ) $ (75,623 ) $ (19,637 )
                   
                   

Weighted average common units outstanding

    88,331,653     58,909,389     81,267,742     53,336,969  
                   
                   

Loss per common unit—basic and diluted

  $ (0.34 ) $ (0.05 ) $ (0.93 ) $ (0.37 )
                   
                   

(1)
The net income allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights, which are described in Note 10.

(2)
All outstanding subordinated units converted to common units in August 2014. Since the subordinated units did not share in the distribution of cash generated during the three months

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 3—Earnings Per Unit (Continued)

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

Cash and cash equivalents

  $ 1,469  

Accounts receivable—trade

    197,349  

Accounts receivable—affiliates

    528  

Inventories

    426,913  

Prepaid expenses and other current assets

    15,373  

Property, plant and equipment:

       

Refined products terminal assets (20 years)

    418,405  

Buildings and leasehold improvements (20 years)

    10,339  

Crude oil tanks and related equipment (20 years)

    28,666  

Vehicles

    1,565  

Land

    56,095  

Information technology equipment

    7,851  

Other

    12,592  

Construction in progress

    4,487  

Goodwill(1)

    29,118  

Intangible assets:

       

Customer relationships (7 years)

    50,000  

Pipeline capacity rights (30 years)

    87,000  

Trade names (indefinite life)

    5,000  

Equity method investments

    250,000  

Other noncurrent assets

    3,911  

Accounts payable—trade

    (140,597 )

Accounts payable—affiliates

    (69 )

Accrued expenses and other payables

    (73,565 )

Advance payments received from customers

    (1,919 )

Long-term debt

    (234,000 )

Other noncurrent liabilities

    (34,856 )

Noncontrolling interests

    (567,120 )
       

Fair value of net assets acquired

  $ 554,535  
       
       

(1)
Included in the refined products and renewables segment.

        Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entity and the Partnership, the opportunity to use the acquired business as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

        The intangible asset for pipeline capacity rights relates to capacity allocations on a third-party refined products pipeline. Demand for use of this pipeline exceeds the pipeline's capacity, and the limited capacity is allocated based on a shipper's historical shipment volumes.

        The fair value of the noncontrolling interests was calculated by multiplying the closing price of TLP's common units on the acquisition date by the number of TLP common units held by parties other than us.

        We recorded in the acquisition accounting a liability of $2.5 million related to certain crude oil contracts with terms that were unfavorable at current market conditions. We amortized this balance to cost of sales during the three months ended September 30, 2014.

        Employees of TransMontaigne participate in a plan whereby they are entitled to certain termination benefits in the event of a change in control of TransMontaigne and a subsequent change in job status. We recorded expense of $2.7 million during the three months ended September 30, 2014 related to these termination benefits, and we may record additional expense in future quarters as we continue our integration efforts.

        The operations of TransMontaigne have been included in our condensed consolidated statements of operations since TransMontaigne was acquired on July 1, 2014. Our condensed consolidated statements of operations for the three months and six months ended September 30, 2014 include revenues of $1.1 billion and an operating loss of $0.3 million that were generated by the operations of TransMontaigne. We have not provided supplemental pro forma financial information as though the business combination had occurred on April 1, 2013. The previous owner of TransMontaigne conducted trading operations, whereas we strive to generate reliable and predictable cash flows. Because of the difference in strategies between the pre-acquisition and post-acquisition periods, the pre-acquisition operations of TransMontaigne have limited importance as an indicator of post-acquisition results.

        On July 10, 2014, we submitted a nonbinding proposal to the conflicts committee of the board of directors of TLP's general partner. Under this proposal, each outstanding unit of TLP would be exchanged for one of our common units. On August 15, 2014, we and TLP's general partner terminated discussions regarding our previously submitted nonbinding proposal to acquire the outstanding common units of TLP.

Water Solutions Facilities

        As described below, we are party to a development agreement that provides us a right to purchase water disposal facilities developed by the other party to the agreement. During the six months ended September 30, 2014, we purchased four water disposal facilities under this development agreement. We also purchased a 75% interest in one additional water disposal facility in July 2014 from a different seller. On a combined basis, we paid $82.9 million of cash for these five water disposal facilities.

        We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these business combinations. The estimates of fair value reflected at September 30, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2015. We have

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

preliminarily estimated the fair values of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable—trade

  $ 939  

Inventories

    253  

Prepaid expenses and other current assets

    62  

Property, plant and equipment:

       

Water treatment facilities and equipment (5 - 40 years)

    23,066  

Buildings and leasehold improvements (3 - 7 years)

    2,599  

Land

    1,010  

Other (7 years)

    33  

Goodwill

    57,777  

Other noncurrent assets

    50  

Accounts payable—trade

    (58 )

Accrued expenses and other payables

    (1,092 )

Other noncurrent liabilities

    (149 )

Noncontrolling interest

    (1,620 )
       

Fair value of net assets acquired

  $ 82,870  
       
       

        Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entity and the Partnership and the opportunity to use the acquired business as a platform for growth. We estimate that all of the goodwill will be deductible for federal income tax purposes.

        The operations of these water disposal facilities have been included in our condensed consolidated statement of operations since their acquisition date. Our condensed consolidated statement of operations for the quarter ended September 30, 2014 includes revenues of $7.1 million and operating income of $1.5 million that were generated by the operations of these water disposal facilities.

Retail Propane Acquisitions

        During the six months ended September 30, 2014, we completed three acquisitions of retail propane businesses. On a combined basis, we paid $6.4 million of cash to acquire these assets and operations. The agreements for these acquisitions contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in certain of these business combinations, and as a result, the estimates of fair value reflected at September 30, 2014 are subject to change.

Water Supply Company

        On June 9, 2014, we paid cash of $15.0 million in exchange for an interest in a water supply company operating in the DJ Basin. We account for this investment using the equity method of accounting.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

Year Ended March 31, 2014

        As described in Note 2, pursuant to GAAP, an entity is allowed a reasonable period of time to obtain the information necessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination. The business combinations for which this measurement period was still open as of March 31, 2014 are summarized below.

Gavilon Energy

        On December 2, 2013, we completed a business combination in which we acquired Gavilon Energy. We paid $832.4 million of cash, net of cash acquired, in exchange for these assets and operations. The acquisition agreement also contemplates a post-closing adjustment to the purchase price for certain working capital items.

        The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas, and Louisiana, a 50% interest in Glass Mountain, which owns a crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma, and an 11% interest in an ethanol production facility in the Midwest. The operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids and owned and leased crude oil storage in Cushing, Oklahoma.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

        During the three months ended September 30, 2014, we completed the acquisition accounting for this business combination. The following table presents the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for this acquisition:

 
  Final   Estimated at
at
March 31,
2014
  Change  
 
  (in thousands)
 

Accounts receivable—trade

  $ 326,484   $ 349,529   $ (23,045 )

Accounts receivable—affiliates

    2,564     2,564      

Inventories

    107,430     107,430      

Prepaid expenses and other current assets

    68,322     68,322      

Property, plant and equipment:

                   

Vehicles (3 years)

    327     791     (464 )

Crude oil tanks and related equipment (3 - 40 years)

    83,797     77,429     6,368  

Information technology equipment (3 - 7 years)

    4,049     4,046     3  

Buildings and leasehold improvements (3 - 40 years)

    7,817     7,716     101  

Land

    6,427     6,427      

Tank bottoms

    16,930     15,230     1,700  

Other (7 years)

    162     170     (8 )

Construction in progress

    7,180     7,190     (10 )

Goodwill(1)

    342,769     359,169     (16,400 )

Intangible assets:

                   

Customer relationships (10 - 20 years)

    107,950     101,600     6,350  

Lease agreements (1 - 5 years)

    8,700     8,700      

Pipeline capacity rights (30 years)

    7,800         7,800  

Investments in unconsolidated entities

    183,000     178,000     5,000  

Other noncurrent assets

    2,287     9,918     (7,631 )

Accounts payable—trade

    (342,792 )   (342,792 )    

Accounts payable—affiliates

    (2,585 )   (2,585 )    

Accrued expenses and other payables

    (49,447 )   (70,999 )   21,552  

Advance payments received from customers

    (10,667 )   (10,667 )    

Other noncurrent liabilities

    (46,056 )   (44,740 )   (1,316 )
               

Fair value of net assets acquired

  $ 832,448   $ 832,448   $  
               
               

(1)
Primarily included in the crude oil logistics segment.

        We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

        The acquisition method of accounting requires that executory contracts that are at unfavorable terms relative to current market conditions at the acquisition date be recorded as assets or liabilities in the acquisition accounting. Since certain crude oil storage lease commitments were at unfavorable terms relative to current market conditions, we recorded a liability of $15.9 million related to these lease commitments in the acquisition accounting, and we amortized $5.0 million of this balance through cost of sales during the six months ended September 30, 2014. We will amortize the remainder of this liability over the term of the leases. The future amortization of this liability is shown below (in thousands):

Year Ending March 31,
   
 

2015 (six months)

  $ 3,670  

2016

    4,040  

2017

    360  

        Certain personnel who were employees of Gavilon Energy are entitled to a bonus, half of which was payable upon successful completion of the business combination and the remainder of which is payable in December 2014. We are recording this as compensation expense over the vesting period. We recorded expense of $5.2 million during the six months ended September 30, 2014 related to these bonuses, and we expect to record an additional expense of $1.6 million during the quarter ending December 31, 2014.

Oilfield Water Lines, LP

        On August 2, 2013, we completed a business combination with entities affiliated with Oilfield Water Lines LP (collectively, "OWL"), whereby we acquired water disposal and transportation assets in Texas. We issued 2,463,287 common units, valued at $68.6 million, and paid $167.7 million of cash, net of cash acquired, in exchange for OWL. During the three months ended June 30, 2014, we completed the acquisition accounting for this business combination. The following table presents the final

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed in the acquisition of OWL:

 
  Final   Estimated at
March 31,
2014
  Change  
 
  (in thousands)
 

Accounts receivable—trade

  $ 6,837   $ 7,268   $ (431 )

Inventories

    154     154      

Prepaid expenses and other current assets

    402     402      

Property, plant and equipment:

                   

Vehicles (5 - 10 years)

    8,143     8,157     (14 )

Water treatment facilities and equipment (3 - 30 years)

    23,173     23,173      

Buildings and leasehold improvements (7 - 30 years)

    2,198     2,198      

Land

    710     710      

Other (3 - 5 years)

    53     53      

Intangible assets:

                   

Customer relationships (8 - 10 years)

    110,000     110,000      

Non-compete agreements (3 years)

    2,000     2,000      

Goodwill

    90,144     89,699     445  

Accounts payable—trade

    (6,469 )   (6,469 )    

Accrued expenses and other payables

    (992 )   (992 )    

Other noncurrent liabilities

    (64 )   (64 )    
               

Fair value of net assets acquired

  $ 236,289   $ 236,289   $  
               
               

        We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

Other Water Solutions Acquisitions

        During the year ended March 31, 2014, we completed two separate acquisitions of businesses to expand our water solutions operations in Texas. On a combined basis, we issued 222,381 common units, valued at $6.8 million, and paid $151.6 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. During the three months ended June 30, 2014, we completed the acquisition accounting for these business combinations. The following table presents the final

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these acquisitions:

 
  Final   Estimated at
March 31,
2014
  Change  
 
  (in thousands)
 

Accounts receivable—trade

  $ 2,146   $ 2,146   $  

Inventories

    192     192      

Prepaid expenses and other current assets

    62     61     1  

Property, plant and equipment:

                   

Vehicles (5 - 10 years)

    76     90     (14 )

Water treatment facilities and equipment (3 - 30 years)

    11,717     14,394     (2,677 )

Buildings and leasehold improvements (7 - 30 years)

    3,278     1,906     1,372  

Land

    207     206     1  

Other (3 - 5 years)

    12     12      

Intangible assets:

                   

Customer relationships (8 - 10 years)

    72,000     72,000      

Trade names (indefinite life)

    3,325     3,325      

Non-compete agreements (3 years)

    260     260      

Water facility development agreement (5 years)

    14,000     14,000      

Water facility option agreement

    2,500     2,500      

Goodwill

    49,067     47,750     1,317  

Accounts payable—trade

    (119 )   (119 )    

Accrued expenses and other payables

    (293 )   (293 )    

Other noncurrent liabilities

    (64 )   (64 )    
               

Fair value of net assets acquired

  $ 158,366   $ 158,366   $  
               
               

        As part of one of these business combinations, we entered into an option agreement with the seller of the business whereby we had the option to purchase a saltwater disposal facility that was under construction. We recorded an intangible asset of $2.5 million at the acquisition date related to this option agreement. On March 1, 2014, we purchased the saltwater disposal facility for additional cash consideration of $3.7 million.

        In addition, as part of one of these business combinations, we entered into a development agreement that provides us a right to purchase water disposal facilities that may be developed by the seller through June 2018. On March 1, 2014, we purchased our first water disposal facility pursuant to the development agreement for $21.0 million.

        We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these business combinations. The estimates of fair value reflected at September 30, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending December 31, 2014. We

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

have preliminarily estimated the fair values of the assets acquired (and useful lives) and liabilities assumed as follows:

 
  Estimated At    
 
 
  September 30,
2014
  March 31,
2014
  Change  
 
  (in thousands)
 

Accounts receivable—trade

  $ 124   $ 245   $ (121 )

Inventories

    119     197     (78 )

Property, plant and equipment:

                   

Water treatment facilities and equipment (3 - 30 years)

    10,539     10,540     (1 )

Buildings and leasehold improvements (7 - 30 years)

    1,130     1,130      

Land

    213     213      

Other (3 - 5 years)

    1     1      

Goodwill

    15,443     15,281     162  

Accounts payable—trade

    (232 )   (263 )   31  

Accrued expenses and other payables

        (7 )   7  

Other noncurrent liabilities

    (50 )   (50 )    
               

Fair value of net assets acquired

  $ 27,287   $ 27,287   $  
               
               

Crude Oil Logistics Acquisitions

        During the year ended March 31, 2014, we completed two separate acquisitions of businesses to expand our crude oil logistics operations in Texas and Oklahoma. On a combined basis, we issued 175,211 common units, valued at $5.3 million, and paid $67.8 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. During the three months ended June 30, 2014, we completed the acquisition accounting for these business combinations. The following table

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

presents the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these acquisitions:

 
  Final   Estimated at
March 31,
2014
  Change  
 
  (in thousands)
 

Accounts receivable—trade

  $ 1,221   $ 1,235   $ (14 )

Inventories

    1,021     1,021      

Prepaid expenses and other current assets

    58     54     4  

Property, plant and equipment:

                   

Vehicles (5 - 10 years)

    2,980     2,977     3  

Buildings and leasehold improvements (5 - 30 years)

    58     280     (222 )

Crude oil tanks and related equipment (2 - 30 years)

    3,822     3,462     360  

Barges and towboats (20 years)

    20,065     20,065      

Other (3 - 5 years)

    57     53     4  

Intangible assets:

                   

Customer relationships (3 years)

    13,300     6,300     7,000  

Non-compete agreements (3 years)

    35     35      

Trade names (indefinite life)

    530     530      

Goodwill

    30,730     37,867     (7,137 )

Accounts payable—trade

    (521 )   (665 )   144  

Accrued expenses and other payables

    (266 )   (124 )   (142 )
               

Fair value of net assets acquired

  $ 73,090   $ 73,090   $  
               
               

Retail Propane and Liquids Acquisitions

        During the year ended March 31, 2014, we completed four acquisitions of retail propane businesses and the acquisition of four natural gas liquids terminals. On a combined basis, we paid $21.9 million of cash to acquire these assets and operations. The agreements for certain of these acquisitions contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in certain of these business combinations, and as a result, the estimates of fair value reflected at September 30, 2014 are subject to change.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 5—Property, Plant and Equipment

        Our property, plant and equipment consists of the following:

Description and Estimated Useful Lives
  September 30,
2014
  March 31,
2014
 
 
  (in thousands)
 

Natural gas liquids terminal assets (2 - 30 years)

  $ 127,258   $ 75,141  

Refined products and renewables terminal assets and equipment (20 years)

    419,411      

Retail propane equipment (2 - 30 years)

    167,825     160,758  

Vehicles and railcars (3 - 25 years)

    172,799     152,676  

Water treatment facilities and equipment (3 - 30 years)

    209,644     180,985  

Crude oil tanks and related equipment (2 - 40 years)

    145,287     106,125  

Barges and towboats (5 - 40 years)

    56,094     52,217  

Information technology equipment (3 - 7 years)

    30,519     20,768  

Buildings and leasehold improvements (3 - 40 years)

    77,415     60,004  

Land

    88,350     30,241  

Tank bottoms

    17,679     13,403  

Other (3 - 30 years)

    16,770     6,341  

Construction in progress

    57,319     80,251  
           

    1,586,370     938,910  

Less: Accumulated depreciation

    (153,057 )   (109,564 )
           

Net property, plant and equipment

  $ 1,433,313   $ 829,346  
           
           

        Depreciation expense was $28.4 million and $13.7 million during the three months ended September 30, 2014 and 2013, respectively, and $46.9 million and $27.2 million during the six months ended September 30, 2014 and 2013, respectively.

        Crude oil volumes required for the operation of storage tanks, known as tank bottoms, are recorded at historical cost. Tank bottoms are the volume of crude oil that must be maintained in a storage tank to enable operation of the storage tank. We recover tank bottom crude oil when we no longer use the storage tanks or the storage tanks are removed from service. At September 30, 2014, tank bottoms consisted of approximately 185,000 barrels.

Note 6—Goodwill and Intangible Assets

        The changes in the balance of goodwill during the six months ended September 30, 2014 were as follows (in thousands):

Beginning of period

  $ 1,107,006  

Revisions to acquisition accounting (Note 4)

    (21,614 )

Acquisitions (Note 4)

    86,895  

Disposal

    (1,797 )
       

End of period

  $ 1,170,490  
       
       

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 6—Goodwill and Intangible Assets (Continued)

        Goodwill by reportable segment is as follows:

 
  September 30,
2014
  March 31,
2014
 
 
  (in thousands)
 

Crude oil logistics

  $ 579,845   $ 606,383  

Water solutions

    320,106     262,203  

Liquids

    91,135     90,135  

Retail propane

    114,285     114,285  

Refined products and renewables

    65,119     34,000  
           

Total

  $ 1,170,490   $ 1,107,006  
           
           

        Our intangible assets consist of the following:

 
   
  September 30, 2014   March 31, 2014  
 
  Amortizable
Lives
  Gross
Carrying
Amount
  Accumulated
Amortization
  Gross
Carrying
Amount
  Accumulated
Amortization
 
 
   
  (in thousands)
 

Amortizable—

                             

Customer relationships(1)

  3 - 20 years   $ 761,992   $ 119,439   $ 697,405   $ 83,261  

Pipeline capacity rights

  30 years     94,800     942          

Water facility development agreement

  5 years     14,000     3,500     14,000     2,100  

Executory contracts and other agreements

  5 - 10 years     23,920     16,367     23,920     13,190  

Non-compete agreements

  2 - 7 years     14,412     8,302     14,161     6,388  

Trade names

  2 - 10 years     14,539     5,197     15,489     3,081  

Debt issuance costs

  5 - 10 years     53,289     12,737     44,089     8,708  
                       

Total amortizable

        976,952     166,484     809,064     116,728  

Non-amortizable—

 

 

   
 
   
 
   
 
   
 
 

Trade names

        27,620           22,620        
                       

Total

      $ 1,004,572   $ 166,484   $ 831,684   $ 116,728  
                       
                       

(1)
The weighted-average remaining amortization period for customer relationship intangible assets is approximately 9 years.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 6—Goodwill and Intangible Assets (Continued)

        Amortization expense is as follows:

 
  Three Months Ended
September 30,
  Six Months Ended
September 30,
 
Recorded In
  2014   2013   2014   2013  
 
  (in thousands)
 

Depreciation and amortization

  $ 21,711   $ 11,324   $ 42,604   $ 20,600  

Cost of sales

    1,984     949     4,121     1,574  

Interest expense

    2,117     1,065     4,029     2,462  
                   

Total

  $ 25,812   $ 13,338   $ 50,754   $ 24,636  
                   
                   

        Expected amortization of our intangible assets is as follows (in thousands):

Year Ending March 31,
   
 

2015 (six months)

  $ 50,570  

2016

    97,432  

2017

    90,795  

2018

    86,818  

2019

    79,587  

Thereafter

    405,266  
       

Total

  $ 810,468  
       
       

Note 7—Long-Term Debt

        Our long-term debt consists of the following:

 
  September 30,
2014
  March 31,
2014
 
 
  (in thousands)
 

Revolving credit facility—

             

Expansion capital borrowings

  $ 137,000   $ 532,500  

Working capital borrowings

    942,500     389,500  

5.125% Notes due 2019

    400,000      

6.875% Notes due 2021

    450,000     450,000  

6.650% Notes due 2022

    250,000     250,000  

TLP credit facility

    252,000      

Other long-term debt

    10,913     14,914  
           

    2,442,413     1,636,914  

Less—current maturities

    5,062     7,080  
           

Long-term debt

  $ 2,437,351   $ 1,629,834  
           
           

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 7—Long-Term Debt (Continued)

Credit Agreement

        On June 19, 2012, we entered into a credit agreement (as amended, the "Credit Agreement") with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the "Working Capital Facility") and a revolving credit facility to fund acquisitions and expansion projects (the "Expansion Capital Facility," and together with the Working Capital Facility, the "Revolving Credit Facility").

        The Working Capital Facility had a total capacity of $1.335 billion for cash borrowings and letters of credit at September 30, 2014. At that date, we had outstanding borrowings of $942.5 million and outstanding letters of credit of $209.2 million on the Working Capital Facility. The Expansion Capital Facility had a total capacity of $858.0 million for cash borrowings at September 30, 2014. At that date, we had outstanding borrowings of $137.0 million on the Expansion Capital Facility. The capacity available under the Working Capital Facility may be limited by a "borrowing base," as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time.

        The commitments under the Credit Agreement expire on November 5, 2018. We have the right to prepay outstanding borrowings under the Credit Agreement without incurring any penalties, and prepayments of principal may be required if we enter into certain transactions to sell assets or obtain new borrowings.

        All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 0.50% to 1.50% per annum or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At September 30, 2014, all borrowings under the Credit Agreement were LIBOR borrowings with an interest rate at September 30, 2014 of 1.91%, calculated as the LIBOR rate of 0.16% plus a margin of 1.75%. At September 30, 2014, the interest rate in effect on letters of credit was 2.00%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. At September 30, 2014, our outstanding borrowings and interest rates under our Revolving Credit Facility were as follows (dollars in thousands):

 
  Amount   Rate  

Expansion Capital Facility—

             

LIBOR borrowings

  $ 137,000     1.91 %

Working Capital Facility—

             

LIBOR borrowings

    942,500     1.91 %

        The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our leverage ratio, as defined in the Credit Agreement, cannot exceed 4.25 to 1 at any quarter end. At September 30, 2014, our leverage ratio was approximately 3.4 to 1. The Credit Agreement also specifies that our interest coverage ratio, as defined in the Credit Agreement, cannot be less than 2.75 to 1 at any quarter end. At September 30, 2014, our interest coverage ratio was approximately 4.8 to 1.

        The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 7—Long-Term Debt (Continued)

indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.

        At September 30, 2014, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

        On July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the "2019 Notes") in a private placement exempt from registration under the Securities Act of 1933, as amended (the "Securities Act"), pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $393.5 million, after the initial purchasers' discount of $6.0 million and estimated offering costs of $0.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

        The 2019 Notes mature on July 15, 2019. Interest is payable on January 15 and July 15 of each year. We have the right to redeem the 2019 Notes prior to the maturity date, although we would be required to pay a premium for early redemption.

        The Partnership and NGL Energy Finance Corp. are co-issuers of the 2019 Notes, and the obligations under the 2019 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The purchase agreement and the indenture governing the 2019 Notes contain various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

        At September 30, 2014, we were in compliance with the covenants under the purchase agreement and indenture governing the 2019 Notes.

        We also entered into a registration rights agreement whereby we have committed to exchange the 2019 Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the 2019 Notes on or before July 9, 2015. If we are unable to fulfill this obligation, we would be required to pay liquidated damages to the holders of the 2019 Notes.

2021 Notes

        On October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the "2021 Notes") in a private placement exempt from registration under the Securities Act pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $438.4 million,

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 7—Long-Term Debt (Continued)

after the initial purchasers' discount of $10.1 million and offering costs of $1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

        The 2021 Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the 2021 Notes prior to the maturity date, although we would be required to pay a premium for early redemption.

        The Partnership and NGL Energy Finance Corp. are co-issuers of the 2021 Notes, and the obligations under the 2021 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The purchase agreement and the indenture governing the 2021 Notes contain various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

        At September 30, 2014, we were in compliance with the covenants under the purchase agreement and indenture governing the 2021 Notes.

        We also entered into a registration rights agreement whereby we have committed to exchange the 2021 Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the 2021 Notes on or before October 16, 2014. Our inability to register the notes on time may result in liquidated damages of approximately $0.1 million per month.

2022 Notes

        On June 19, 2012, we entered into a Note Purchase Agreement (as amended, the "Note Purchase Agreement") whereby we issued $250.0 million of Senior Notes in a private placement (the "2022 Notes"). The 2022 Notes bear interest at a fixed rate of 6.65%. Interest is payable quarterly. The 2022 Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to prepay outstanding principal, although we would incur a prepayment penalty. The 2022 Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

        The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create or permit certain liens, (iv) create or permit restrictions on the ability of certain of our subsidiaries to pay dividends or make other distributions to us, (v) enter into transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate or merge or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains substantially the same leverage ratio and interest coverage ratio requirements as our Credit Agreement, which is described above.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 7—Long-Term Debt (Continued)

        The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary grace and cure periods): (i) nonpayment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the 2022 Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the Note Purchase Agreement, the 2022 Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregate principal amount of the then outstanding 2022 Notes of any series may declare all of the 2022 Notes of such series to be due and payable immediately.

        At September 30, 2014, we were in compliance with the covenants under the Note Purchase Agreement.

TLP Credit Facility

        On March 9, 2011, TLP entered into an amended and restated senior secured credit facility ("TLP Credit Facility"), which has been subsequently amended from time to time. The TLP Credit Facility provides for a maximum borrowing line of credit equal to the lesser of (i) $350 million and (ii) 4.75 times Consolidated EBITDA (as defined in the TLP Credit Facility: $352.9 million at September 30, 2014). TLP may elect to have loans under the TLP Credit Facility that bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLP also pays a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.50% per annum, depending on the total leverage ratio then in effect. TLP's obligations under the TLP Credit Facility are secured by a first priority security interest in favor of the lenders in the majority of TLP assets.

        The terms of the TLP Credit Facility include covenants that restrict TLP's ability to make cash distributions, acquisitions and investments, including investments in joint ventures. TLP may make distributions of cash to the extent of its "available cash" as defined in the TLP partnership agreement. TLP may make acquisitions and investments that meet the definition of "permitted acquisitions"; "other investments" which may not exceed 5% of "consolidated net tangible assets"; and "permitted JV investments". Permitted JV investments include up to $225 million of investments in BOSTCO, the "Specified BOSTCO Investment". In addition to the Specified BOSTCO Investment, under the terms of the TLP Credit Facility, TLP may make an additional $75 million of other permitted JV investments (including additional investments in BOSTCO). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 9, 2016.

        The TLP Credit Facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the TLP Credit Facility are (i) a total leverage ratio test (not to exceed 4.75 times), (ii) a

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 7—Long-Term Debt (Continued)

senior secured leverage ratio test (not to exceed 3.75 times) in the event TLP issues senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times).

        If TLP were to fail any financial performance covenant, or any other covenant contained in the TLP Credit Facility, TLP would seek a waiver from its lenders under such facility. If TLP was unable to obtain a waiver from its lenders and the default remained uncured after any applicable grace period, TLP would be in breach of the TLP Credit Facility, and the lenders would be entitled to declare all outstanding borrowings immediately due and payable. TLP was in compliance with all of the financial covenants under the TLP Credit Facility as of September 30, 2014.

        At September 30, 2014, TLP had $252.0 million of outstanding borrowings under the TLP Credit Facility and no outstanding letters of credit.

        The following table summarizes our basis in the assets and liabilities of TLP at September 30, 2014, inclusive of the impact of our acquisition accounting for the business combination with TransMontaigne (in thousands):

Cash and cash equivalents

  $ 726  

Accounts receivable—trade, net

    12,252  

Accounts receivable—affiliates

    1,105  

Inventories

    1,613  

Prepaid expenses and other current assets

    1,363  

Property, plant and equipment, net

    504,272  

Goodwill

    29,118  

Intangible assets, net

    38,571  

Investments in unconsolidated entities

    268,410  

Other noncurrent assets

    1,910  

Accounts payable—trade

    (4,009 )

Accounts payable—affiliates

    (146 )

Accrued expenses and other payables

    (11,625 )

Advanced payments received from customers

    (141 )

Long-term debt

    (252,000 )

Other noncurrent liabilities

    (4,247 )
       

Net assets

  $ 587,172  
       
       

Other Long-Term Debt

        We have executed various noninterest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also have certain notes payable related to equipment financing.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 7—Long-Term Debt (Continued)

Debt Maturity Schedule

        The scheduled maturities of our long-term debt are as follows at September 30, 2014:

Year Ending March 31,
  Revolving
Credit
Facility
  2019
Notes
  2021
Notes
  2022
Notes
  TLP
Credit
Facility
  Other
Long-Term
Debt
  Total  
 
  (in thousands)
 

2015 (six months)

  $   $   $   $   $   $ 2,345   $ 2,345  

2016

                    252,000     3,128     255,128  

2017

                        2,362     2,362  

2018

                25,000         1,459     26,459  

2019

    1,079,500             50,000         1,438     1,130,938  

Thereafter

        400,000     450,000     175,000         181     1,025,181  
                               

Total

  $ 1,079,500   $ 400,000   $ 450,000   $ 250,000   $ 252,000   $ 10,913   $ 2,442,413  
                               
                               

Note 8—Income Taxes

        We qualify as a partnership for income tax purposes. As such, we generally do not pay United States federal income tax. Rather, each owner reports his or her share of our income or loss on his or her individual tax return. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined, as we do not have access to information regarding each partner's basis in the Partnership.

        We have certain taxable corporate subsidiaries in the United States and in Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales. We utilize the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.

        A publicly-traded partnership is required to generate at least 90% of its gross income (as defined for federal income tax purposes) from certain qualifying sources. Income generated by our taxable corporate subsidiaries is excluded from this qualifying income calculation. Although we routinely generate income outside of our corporate subsidiaries that is non-qualifying, we believe that at least 90% of our gross income has been qualifying income for each of the calendar years since our initial public offering.

        We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 8—Income Taxes (Continued)

financial statements. We had no material uncertain tax positions that required recognition in the consolidated financial statements at September 30, 2014.

Note 9—Commitments and Contingencies

Legal Contingencies

        We are party to various claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of our management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of our liabilities may change materially as circumstances develop.

Customer Dispute

        A customer of our crude oil logistics segment disputed the transportation rate schedule we used to bill the customer for services that we provided from November 2012 through February 2013, which was the same rate schedule that Pecos Gathering & Marketing, L.L.C. and certain of its affiliated companies (collectively, "Pecos"), used to bill the customer from April 2011 through October 2012 (prior to our November 1, 2012 acquisition of Pecos). The customer disputed a portion of the amount we charged for services we provided from November 2012 through February 2013. In May 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. Later in May 2013, the customer filed an answer and counterclaim seeking to recover certain amounts that it paid to Pecos prior to our acquisition of Pecos.

        During August 2013, the customer notified us that it intended to withhold payment due for services performed by us during the period from June 2013 through August 2013, pending resolution of the dispute, although the customer did not dispute the validity of the amounts billed for services performed during this time frame. Upon receiving this notification, we ceased providing services under this contract, and on November 5, 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer.

        During September 2014, we reached an agreement with the former customer whereby the former customer agreed to pay us an agreed-upon amount to dismiss its claims against us, in return for which we agreed to dismiss our other claims against the former customer. We did not record a gain or loss upon settlement, as the amount we received approximated the amount we had recorded as receivable from the customer.

Environmental Matters

        Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there can be no assurance that significant costs will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 9—Commitments and Contingencies (Continued)

policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

Asset Retirement Obligations

        We have recorded a liability of $2.7 million at September 30, 2014 for asset retirement obligations. This liability is related to wastewater disposal facilities and crude oil facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

        In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certain other assets. We do not believe the present value of these asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of our facilities, is material to our consolidated financial position or results of operations.

Operating Leases

        We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment. Future minimum lease payments under these agreements at September 30, 2014 are as follows (in thousands):

Year Ending March 31,
   
 

2015 (six months)

  $ 71,007  

2016

    106,384  

2017

    88,666  

2018

    74,265  

2019

    49,907  

Thereafter

    117,125  
       

Total

  $ 507,354  
       
       

        Rental expense relating to operating leases was $29.3 million and $23.6 million during the three months ended September 30, 2014 and 2013, respectively, and $54.6 million and $45.5 million during the six months ended September 30, 2014 and 2013, respectively.

Pipeline Capacity Agreements

        We have executed noncancelable agreements with crude and refined products pipeline operators, which guarantee us minimum monthly shipping capacity on the pipelines. In exchange, we are obligated to pay the minimum shipping fees in the event actual shipments are less than our allotted capacity.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 9—Commitments and Contingencies (Continued)

Future minimum throughput payments under these agreements at September 30, 2014 are as follows (in thousands):

Year Ending March 31,
   
 

2015 (six months)

  $ 41,822  

2016

    95,050  

2017

    82,916  

2018

    62,565  

2019

    51,278  

Thereafter

    107,537  
       

Total

  $ 441,168  
       
       

Sales and Purchase Contracts

        We have entered into sales and purchase contracts for products to be delivered in future periods for which we expect the parties to physically settle the contracts with inventory. At September 30, 2014, we had the following such commitments outstanding:

 
  Volume   Value  
 
  (in thousands)
 

Natural gas liquids fixed-price purchase commitments (gallons)

    88,574   $ 102,000  

Natural gas liquids index-price purchase commitments (gallons)

    528,459     601,719  

Natural gas liquids fixed-price sale commitments (gallons)

    278,391     351,137  

Natural gas liquids index-price sale commitments (gallons)

    370,639     512,900  

Crude oil index-price purchase commitments (barrels)

    4,437     383,153  

Crude oil fixed-price sale commitments (barrels)

    32     2,867  

Crude oil index-price sale commitments (barrels)

    3,920     337,528  

        We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs. Contracts in the table above may have offsetting derivative contracts (described in Note 11) or inventory positions (described in Note 2).

        Certain other forward purchase and sale contracts do not qualify for the normal purchase and normal sale election. These contracts are recorded at fair value on our condensed consolidated balance sheet and are not included in the table above. These contracts are included in the derivative disclosures in Note 11, and represent $44.4 million of our prepaid expenses and other current assets and $36.3 million of our accrued expenses and other payables at September 30, 2014.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 10—Equity

Partnership Equity

        The Partnership's equity consists of a 0.1% general partner interest and a 99.9% limited partner interest, which consists of common units. Prior to August 2014, the Partnership's limited partner interest also included subordinated units. The subordination period ended in August 2014, at which time all remaining subordinated units were converted into common units on a one-for-one basis.

        Our general partner is not obligated to make any additional capital contributions or to guarantee or pay any of our debts and obligations.

Equity Issuances

        On June 23, 2014, we completed a public offering of 8,000,000 common units. We received net proceeds of $338.0 million, after underwriting discounts and commissions of $12.3 million and offering costs of $0.5 million. During July 2014, the underwriters exercised their option to purchase an additional 767,100 units, from which we received net proceeds of $32.4 million.

Distributions to Owners

        Our general partner has adopted a cash distribution policy that requires us to pay a quarterly distribution to unitholders as of the record date to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner and its affiliates, referred to as "available cash." The general partner will also receive, in addition to distributions on its 0.1% general partner interest, additional distributions based on the level of distributions to the limited partners. These distributions are referred to as "incentive distributions." Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

        The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest In Distributions" are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit," until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1%

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 10—Equity (Continued)

general partner interest, assume our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and has not transferred its incentive distribution rights.

 
   
   
  Marginal Percentage
Interest In Distributions
 
 
  Total Quarterly Distribution Per Unit   Unitholders   General Partner  

Minimum quarterly distribution

          $0.337500     99.9 %   0.1 %

First target distribution

    above $0.337500     up to $0.388125     99.9 %   0.1 %

Second target distribution

    above $0.388125     up to $0.421875     86.9 %   13.1 %

Third target distribution

    above $0.421875     up to $0.506250     76.9 %   23.1 %

Thereafter

    above $0.506250           51.9 %   48.1 %

        During the three months ended September 30, 2014, we distributed a total of $61.5 million ($0.5888 per common, subordinated, and general partner notional unit) to our unitholders of record on August 4, 2014, which included an incentive distribution of $9.5 million to the general partner. In October 2014, we declared a distribution of $0.6088 per common unit, to be paid on November 14, 2014 to unitholders of record on November 4, 2014. This distribution is expected to be $65.0 million, including amounts to be paid on common and general partner notional units and the amount to be paid on incentive distribution rights.

Distributions to Noncontrolling Interest Partners

        TLP's general partner has adopted a cash distribution policy that requires it to pay a quarterly distribution to unitholders as of the record date to the extent TLP has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to TLP's general partner and its affiliates, referred to as "available cash." TLP's general partner will also receive, in addition to distributions on its 2.0% general partner interest, additional distributions based on the level of distributions to the limited partners. These distributions are referred to as "incentive distributions." TLP's general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in TLP's partnership agreement.

        The following table illustrates the percentage allocations of available cash from operating surplus between TLP's unitholders and TLP's general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest In Distributions" are the percentage interests of TLP's general partner and TLP's unitholders in any available cash from operating surplus TLP distributes up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit," until available cash from operating surplus TLP distributes reaches the next target distribution level, if any. The percentage interests shown for TLP's unitholders and TLP's general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for TLP's general partner include its 2.0% general partner interest, assume TLP's general partner has

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 10—Equity (Continued)

contributed any additional capital necessary to maintain its 2.0% general partner interest and has not transferred its incentive distribution rights.

 
   
   
  Marginal Percentage
Interest In Distributions
 
 
  Total Quarterly Distribution
Per Unit
  Unitholders   General Partner  

Minimum quarterly distribution

          $0.40     98 %   2 %

First target distribution

    above $0.40     up to $0.44     98 %   2 %

Second target distribution

    above $0.44     up to $0.50     85 %   15 %

Third target distribution

    above $0.50     up to $0.60     75 %   25 %

Thereafter

    above $0.60           50 %   50 %

        During the three months ended September 30, 2014, TLP declared and paid a distribution of $0.665 per unit. The noncontrolling interest owners received a total of $8.7 million from this distribution. Pursuant to the terms of the agreement related to our acquisition of TransMontaigne, we remitted the amount we received on this distribution on our general partner interest, incentive distribution rights, and limited partner interest to the former owners of TransMontaigne.

        In October 2014, TLP declared a distribution of $0.665 per unit, which was paid on November 7, 2014. The noncontrolling interest owners received a total of $8.7 million from this distribution.

Equity-Based Incentive Compensation

        Our general partner has adopted a long-term incentive plan ("LTIP"), which allows for the issuance of equity-based compensation to employees and directors. Our general partner has granted certain restricted units to employees and directors, which will vest in tranches, subject to the continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

        The following table summarizes the restricted unit activity during the six months ended September 30, 2014:

Unvested restricted units at March 31, 2014

    1,311,100  

Units granted

    333,903  

Units vested and issued

    (438,009 )

Units withheld for employee taxes

    (231,194 )

Units forfeited

    (117,000 )
       

Unvested restricted units at September 30, 2014

    858,800  
       
       

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 10—Equity (Continued)

        The scheduled vesting of our unvested restricted units is summarized below:

Vesting Date
  Number of
Awards
 

July 1, 2015

    334,800  

July 1, 2016

    314,000  

July 1, 2017

    178,500  

July 1, 2018

    31,500  
       

Unvested restricted units at September 30, 2014

    858,800  
       
       

        We record the expense for the first tranche of each award on a straight-line basis over the period beginning with the grant date of the awards and ending with the vesting date of the tranche. We record the expense for succeeding tranches over the period beginning with the vesting date of the previous tranche and ending with the vesting date of the tranche.

        At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using the closing price of our common units on the New York Stock Exchange on the balance sheet date, adjusted to reflect the fact that the holders of the unvested units are not entitled to distributions during the vesting period. We estimate the impact of the lack of distribution rights during the vesting period using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth.

        We recorded expense related to restricted unit awards of $13.8 million and $3.2 million during the three months ended September 30, 2014 and 2013, respectively, and $21.7 million and $10.3 million during the six months ended September 30, 2014 and 2013, respectively. We estimate that the future expense we will record on the unvested awards at September 30, 2014 will be as follows (in thousands), after taking into consideration an estimate of forfeitures of approximately 80,000 units. For purposes of this calculation, we used the closing price of our common units on September 30, 2014, which was $39.37.

Year Ending March 31,
   
 

2015 (six months)

  $ 6,343  

2016

    11,516  

2017

    7,262  

2018

    2,237  

2019

    249  
       

Total

  $ 27,607  
       
       

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 10—Equity (Continued)

        Following is a rollforward of the liability related to equity-based compensation, which is reported within accrued expenses and other payables on our condensed consolidated balance sheets (in thousands):

Balance at March 31, 2014

  $ 10,012  

Expense recorded

    21,659  

Value of units vested and issued

    (18,763 )

Taxes paid on behalf of participants

    (9,901 )
       

Balance at September 30, 2014

  $ 3,007  
       
       

        The weighted-average fair value of the awards at September 30, 2014 was $35.16 per common unit, which was calculated as the closing price of the common units on September 30, 2014, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth.

        The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common units. The maximum number of units deliverable under the plan automatically increases to 10% of the issued and outstanding common units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount. Units withheld to satisfy tax withholding obligations will not be considered to be delivered under the LTIP. In addition, if an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available for new awards under the LTIP. At September 30, 2014, 7.1 million units remain available for issuance under the LTIP.

Note 11—Fair Value of Financial Instruments

        Our cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, and other current assets and liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values due to their short-term nature.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 11—Fair Value of Financial Instruments (Continued)

Commodity Derivatives

        The following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported on the condensed consolidated balance sheet at September 30, 2014:

 
  Derivative
Assets
  Derivative
Liabilities
 
 
  (in thousands)
 

Level 1 measurements

  $ 48,632   $ (5,378 )

Level 2 measurements

    51,389     (38,280 )
           

    100,021     (43,658 )

Netting of counterparty contracts(1)

    (4,635 )   4,635  

Cash collateral held

    (13,704 )    
           

Commodity derivatives on condensed consolidated balance sheet

  $ 81,682   $ (39,023 )
           
           

(1)
Relates to derivative assets and liabilities that are expected to be net settled on an exchange or through a master netting arrangement with the counterparty.

        The following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported on the condensed consolidated balance sheet at March 31, 2014:

 
  Derivative
Assets
  Derivative
Liabilities
 
 
  (in thousands)
 

Level 1 measurements

  $ 4,990   $ (3,258 )

Level 2 measurements

    49,605     (43,303 )
           

    54,595     (46,561 )

Netting of counterparty contracts(1)

    (4,347 )   4,347  

Net cash collateral provided

    456      
           

Commodity derivatives on condensed consolidated balance sheet

  $ 50,704   $ (42,214 )
           
           

(1)
Relates to derivative assets and liabilities that are expected to be net settled on an exchange or through a master netting arrangement with the counterparty.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 11—Fair Value of Financial Instruments (Continued)

        Our commodity derivative assets and liabilities are reported in the following accounts on the condensed consolidated balance sheets:

 
  September 30,
2014
  March 31,
2014
 
 
  (in thousands)
 

Prepaid expenses and other current assets

  $ 81,682   $ 50,704  

Accrued expenses and other payables

    (39,023 )   (42,214 )
           

Net commodity derivative asset

  $ 42,659   $ 8,490  
           
           

        The following table summarizes our open commodity derivative contract positions at September 30, 2014 and March 31, 2014. We do not account for these derivatives as hedges.

Contracts
  Settlement Period   Total
Notional
Units
(Barrels)
  Fair Value
of Net
Assets
(Liabilities)
 
 
   
  (in thousands)
 

At September 30, 2014—

                 

Cross-commodity(1)

  October 2014 - March 2015     (12 ) $ (1,283 )

Crude oil fixed-price(2)

  October 2014 - December 2015     (1,638 )   9,380  

Crude oil index(3)

  October 2014 - July 2015     2,195     4,397  

Propane fixed-price(4)

  October 2014 - March 2015     1,238     53  

Refined products fixed-price(5)

  October 2014 - July 2015     (4,475 )   38,712  

Renewable products fixed-price(6)

  October 2014 - December 2015     (14 )   5,104  
                 

              56,363  

Net cash collateral held

              (13,704 )
                 

Net commodity derivatives on condensed consolidated balance sheet

            $ 42,659  
                 
                 

At March 31, 2014—

                 

Cross-commodity(1)

  April 2014 - March 2015     140   $ (1,876 )

Crude oil fixed-price(2)

  April 2014 - March 2015     (1,600 )   (2,796 )

Crude oil index(3)

  April 2014 - December 2015     3,598     6,099  

Propane fixed-price(4)

  April 2014 - March 2015     60     1,753  

Refined products fixed-price(5)

  April 2014 - July 2014     732     560  

Renewable products fixed-price(6)

  April 2014 - July 2014     106     4,084  

Other

  April 2014         210  
                 

              8,034  

Net cash collateral provided

              456  
                 

Net commodity derivatives on condensed consolidated balance sheet

            $ 8,490  
                 
                 

(1)
Cross-commodity—Our operating segments may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. The contracts listed in this table as "Cross-commodity" represent derivatives we have entered into as an economic hedge against the risk of one commodity price moving relative to another commodity price.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 11—Fair Value of Financial Instruments (Continued)

(2)
Crude oil fixed-price—Our crude oil logistics segment routinely purchases crude oil inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as "Crude oil fixed-price" represent derivatives we have entered into as an economic hedge against the risk that crude oil prices will decline while we are holding the inventory.

(3)
Crude oil index—Our crude oil logistics segment may purchase or sell crude oil where the underlying contract pricing mechanisms are tied to different crude oil indices. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. The contracts listed in this table as "Crude oil index" represent derivatives we have entered into as an economic hedge against the risk of one crude oil index moving relative to another crude oil index.

(4)
Propane fixed-price—Our liquids segment routinely purchases propane inventory during the warmer months and stores the propane inventory for sale during the colder months. The contracts listed in this table as "Propane fixed-price" represent derivatives we have entered into as an economic hedge against the risk that propane prices will decline while we are holding the inventory.

(5)
Refined products fixed-price—Our refined products and renewables segment routinely purchases refined products inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as "Refined products fixed-price" represent derivatives we have entered into as an economic hedge against the risk that refined product prices will decline while we are holding the inventory.

(6)
Renewable products fixed-price—Our refined products and renewables segment routinely purchases biodiesel and ethanol inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as "Renewable products fixed-price" represent derivatives we have entered into as an economic hedge against the risk that biodiesel or ethanol prices will decline while we are holding the inventory.

        We recorded the following net gains (losses) from our commodity derivatives to cost of sales:

Three Months Ended
September 30,
  Six Months Ended
September 30,
 
2014   2013   2014   2013  
(in thousands)
 
$ 55,981   $ (10,672 ) $ 38,496   $ (17,881 )

Credit Risk

        We maintain credit policies with regard to our counterparties on the derivative financial instruments that we believe minimize our overall credit risk, including an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single counterparty.

        We may enter into industry standard master netting agreements and may enter into cash collateral agreements requiring the counterparty to deposit funds into a brokerage margin account. The netting agreements reduce our credit risk by providing for net settlement of any offsetting positive and negative exposures with counterparties. The cash collateral agreements reduce the level of our net counterparty credit risk because the amount of collateral represents additional funds that we may access to net settle positions due us, and the amount of collateral adjusts each day in response to changes in the market value of counterparty derivatives.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 11—Fair Value of Financial Instruments (Continued)

        Our counterparties consist primarily of financial institutions and energy companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

        As is customary in the crude oil industry, we generally receive payment from customers for sales of crude oil on a monthly basis. As a result, receivables from individual customers in our crude oil logistics segment are generally higher than the receivables from customers in our other segments.

        Failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our condensed consolidated balance sheets and recognized in our net income.

Interest Rate Risk

        Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At September 30, 2014, we had $1.1 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 1.91%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.3 million, based on borrowings outstanding at September 30, 2014.

        The TLP Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At September 30, 2014, TLP had $252.0 million of outstanding borrowings under the TLP Credit Facility at a rate of 2.66%. A change in interest rates of 0.125% would result in an increase or decrease in TLP's annual interest expense of $0.3 million, based on borrowings outstanding at September 30, 2014.

Fair Value of Notes

        The following table provides estimates of the fair values of our fixed-rate notes at September 30, 2014 (in thousands):

5.125% Notes due 2019

  $ 390,000  

6.875% Notes due 2021

    475,000  

6.650% Notes due 2022

    275,000  

        For the 2019 Notes and the 2021 Notes, the fair value estimates were developed by reference to broker quotes. These estimates would be classified as Level 2 in the fair value hierarchy. For the 2022 Notes, the estimate was developed using observed yields on publicly-traded notes issued by other entities, adjusted for differences in the key terms of those notes and the key terms of our notes (examples include differences in the tenor of the debt, credit standing of the issuer, whether the notes are publicly-traded, and whether the notes are secured or unsecured). These estimates of fair value would be classified as Level 3 in the fair value hierarchy.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 12—Segments

        Our reportable segments are based on the way in which our management structure is organized. Certain financial data related to our segments is shown below. Transactions between segments are recorded based on prices negotiated between the segments.

        Our crude oil logistics segment sells crude oil and provides crude oil transportation services to wholesalers, refiners, and producers. Our water solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production, and generates revenue from the sale of recycled water and recovered hydrocarbons. Our liquids segment supplies propane, butane, and other products, and provides natural gas liquids transportation, terminaling, and storage services to retailers, wholesalers, and refiners. Our retail propane segment sells propane and distillates to end users consisting of residential, agricultural, commercial, and industrial customers, and to certain re-sellers. Our retail propane segment consists of two divisions, which are organized based on the location of the operations. Our refined products and renewables segment provides integrated terminaling, storage, transportation, marketing, and related services for companies engaged in the trading, distribution and marketing of refined petroleum products, ethanol, and biodiesel. This segment began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne.

        Items labeled "corporate and other" in the table below include the operations of a compressor leasing business that we sold in February 2014 and certain natural gas marketing operations that we acquired in our December 2013 acquisition of Gavilon Energy and wound down during fiscal year 2014. The "corporate and other" category also includes certain corporate expenses that are incurred and are not allocated to the reportable segments. This data is included to reconcile the data for the reportable segments to data in our condensed consolidated financial statements.

 
  Three Months Ended
September 30,
  Six Months Ended
September 30,
 
 
  2014   2013   2014   2013  
 
   
   
  (in thousands)
 

Revenues:

                         

Crude oil logistics—

                         

Crude oil sales

  $ 2,108,117   $ 1,013,061   $ 4,035,061   $ 1,941,595  

Crude oil transportation and other

    13,082     9,794     25,196     19,729  

Water solutions—

                         

Water treatment and disposal

    47,572     28,823     89,288     47,511  

Water transportation

    5,147     5,367     10,745     7,192  

Liquids—

                         

Propane sales

    240,433     191,437     462,879     315,274  

Other product sales

    306,625     308,606     594,984     558,459  

Other revenues

    6,814     9,250     12,530     18,114  

Retail propane—

                         

Propane sales

    48,552     40,651     100,578     87,342  

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 12—Segments (Continued)

 
  Three Months Ended
September 30,
  Six Months Ended
September 30,
 
 
  2014   2013   2014   2013  
 
   
   
  (in thousands)
 

Distillate sales

    11,530     10,562     30,225     28,431  

Other revenues

    8,276     8,198     15,457     15,898  

Refined products and renewables—

                         

Refined products sales

    2,489,795         3,476,018      

Renewables sales

    117,425         248,699      

Corporate and other

    1,333     1,485     2,794     2,959  

Elimination of intersegment sales

    (24,175 )   (33,297 )   (75,314 )   (62,610 )
                   

Total revenues

  $ 5,380,526   $ 1,593,937   $ 9,029,140   $ 2,979,894  
                   
                   

Depreciation and Amortization:

                         

Crude oil logistics

  $ 9,240   $ 3,330   $ 18,971   $ 8,014  

Water solutions

    17,573     11,438     34,665     18,794  

Liquids

    3,384     2,672     6,585     5,376  

Retail propane

    7,684     6,871     15,255     14,111  

Refined products and renewables

    11,917         12,761      

Corporate and other

    301     750     1,237     1,490  
                   

Total depreciation and amortization

  $ 50,099   $ 25,061   $ 89,474   $ 47,785  
                   
                   

Operating Income (Loss):

                         

Crude oil logistics

  $ 38   $ 5,884   $ 1,501   $ 12,493  

Water solutions

    14,792     2,913     13,885     5,956  

Liquids

    10,929     14,605     10,016     12,490  

Retail propane

    (3,062 )   (4,520 )   (4,648 )   (6,024 )

Refined products and renewables

    8,822         7,567      

Corporate and other

    (23,749 )   (8,937 )   (41,106 )   (22,312 )
                   

Total operating income (loss)

  $ 7,770   $ 9,945   $ (12,785 ) $ 2,603  
                   
                   

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 12—Segments (Continued)

        The following table summarizes additions to property, plant and equipment for each segment. This information has been prepared on the accrual basis, and includes property, plant and equipment acquired in acquisitions.

 
  Three Months Ended
September 30,
  Six Months Ended
September 30,
 
 
  2014   2013   2014   2013  
 
  (in thousands)
 

Additions to property, plant and equipment:

                         

Crude oil logistics

  $ 39,464   $ 31,336   $ 81,413   $ 35,462  

Water solutions

    40,610     62,473     48,072     70,182  

Liquids

    1,911     13,209     3,070     28,316  

Retail propane

    9,567     4,546     12,411     11,492  

Refined products and renewables

    512,281         512,281      

Corporate and other

    1,809     217     3,262     846  
                   

Total

  $ 605,642   $ 111,781   $ 660,509   $ 146,298  
                   
                   

        The following tables summarize long-lived assets (consisting of net property, plant and equipment, net intangible assets, and goodwill) and total assets by segment:

 
  September 30,
2014
  March 31,
2014
 
 
  (in thousands)
 

Total assets:

             

Crude oil logistics

  $ 2,079,380   $ 1,723,812  

Water solutions

    964,336     875,714  

Liquids

    756,133     577,795  

Retail propane

    506,958     541,832  

Refined products and renewables

    2,183,674     303,230  

Corporate and other

    61,198     144,840  
           

Total

  $ 6,551,679   $ 4,167,223  
           
           

Long-lived assets, net:

             

Crude oil logistics

  $ 996,615   $ 980,978  

Water solutions

    910,467     848,479  

Liquids

    271,567     274,846  

Retail propane

    436,621     438,324  

Refined products and renewables

    772,916     60,720  

Corporate and other

    53,705     47,961  
           

Total

  $ 3,441,891   $ 2,651,308  
           
           

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 13—Transactions with Affiliates

        SemGroup Corporation ("SemGroup") holds ownership interests in us and in our general partner. We sell product to and purchase product from SemGroup, and these transactions are included within revenues and cost of sales in our condensed consolidated statements of operations. We also lease crude oil storage from SemGroup.

        We purchase ethanol from one of our equity method investees. These transactions are reported within cost of sales in our condensed consolidated statements of operations.

        Certain members of our management own interests in entities from which we have purchased products and services and to which we have sold products and services to. The majority of these purchases represented crude oil purchases and are reported within cost of sales in our condensed consolidated statements of operations, although $5.8 million of these transactions during the six months ended September 30, 2014 represented capital expenditures and were recorded as increases to property, plant and equipment. The majority of these sales represented crude oil sales and are reported within revenues in our condensed consolidated statements of operations.

        The above transactions are summarized in the following table:

 
  Three Months Ended
September 30,
  Six Months Ended
September 30,
 
 
  2014   2013   2014   2013  
 
  (in thousands)
 

Sales to SemGroup

  $ 43,427   $ 3,780   $ 117,233   $ 3,780  

Purchases from SemGroup

    45,730     28,377     118,997     47,916  

Purchases from equity method investees

    34,689         70,965      

Sales to equity method investees

    9,131         9,131      

Sales to entities affiliated with management

    1,706     58,769     1,854     109,872  

Purchases from entities affiliated with management

    3,845     48,522     6,984     56,346  

        Receivables from affiliates consist of the following:

 
  September 30,
2014
  March 31,
2014
 
 
  (in thousands)
 

Receivables from SemGroup

  $ 39,331   $ 7,303  

Receivables from entities affiliated with management

    1,705     142  

Receivables from equity method investees

    670      
           

Total

  $ 41,706   $ 7,445  
           
           

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 13—Transactions with Affiliates (Continued)

        Payables to affiliates consist of the following:

 
  September 30,
2014
  March 31,
2014
 
 
  (in thousands)
 

Payables to SemGroup

  $ 44,015   $ 27,738  

Payables to equity method investees

    39,549     48,454  

Payables to entities affiliated with management

    1,743     654  
           

Total

  $ 85,307   $ 76,846  
           
           

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information

        Certain of our wholly-owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the 2019 Notes and the 2021 Notes (described in Note 7). Pursuant to Rule 3-10 of Regulation S-X, we have presented in columnar format the condensed consolidating financial information for NGL Energy Partners LP, NGL Energy Finance Corp. (which, along with NGL Energy Partners LP, is a co-issuer of the 2019 Notes and 2021 Notes), the guarantor subsidiaries on a combined basis, and the non-guarantor subsidiaries on a combined basis in the tables below.

        During the periods presented in the tables below, the status of certain subsidiaries changed, in that they either became guarantors of or ceased to be guarantors of the 2019 Notes and 2021 Notes. Such changes have been given retrospective application in the tables below.

        There are no significant restrictions upon the ability of the parent or any of the guarantor subsidiaries to obtain funds from their respective subsidiaries by dividend or loan. None of the assets of the guarantor subsidiaries represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.

        For purposes of the tables below, (i) the condensed consolidating financial information is presented on a legal entity basis, not a business segment basis, (ii) investments in consolidated subsidiaries are accounted for as equity method investments, and (iii) contributions, distributions, and advances to or from consolidated entities are reported on a net basis within net changes in advances with consolidated entities in the condensed consolidating cash flow tables below.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)


NGL ENERGY PARTNERS LP
Condensed Consolidating Balance Sheet
(U.S. Dollars in Thousands)

 
  September 30, 2014  
 
  NGL Energy
Partners LP
(Parent)(1)
  NGL Energy
Finance Corp.
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

ASSETS

                                     

CURRENT ASSETS:

                                     

Cash and cash equivalents

  $ 2,841   $   $ 7,823   $ 1,159   $   $ 11,823  

Accounts receivable—trade, net of allowance for doubtful accounts

            1,419,442     13,675         1,433,117  

Accounts receivable—affiliates

            41,035     671         41,706  

Inventories

            937,814     3,775         941,589  

Prepaid expenses and other current assets

            155,332     1,486         156,818  
                           

Total current assets

    2,841         2,561,446     20,766         2,585,053  

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation

   
   
   
863,694
   
569,619
   
   
1,433,313
 

GOODWILL

            1,139,374     31,116         1,170,490  

INTANGIBLE ASSETS, net of accumulated amortization

    1,307     17,619     778,960     40,202         838,088  

INVESTMENTS IN UNCONSOLIDATED ENTITIES

            214,234     268,410         482,644  

NET INTERCOMPANY RECEIVABLES (PAYABLES)

    248,893     849,526     (1,026,605 )   (71,814 )        

INVESTMENTS IN CONSOLIDATED SUBSIDIARIES

    1,743,573         10,470         (1,754,043 )    

OTHER NONCURRENT ASSETS

            40,035     2,056         42,091  
                           

Total assets

  $ 1,996,614   $ 867,145   $ 4,581,608   $ 860,355   $ (1,754,043 ) $ 6,551,679  
                           
                           

F-129


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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

 
  September 30, 2014  
 
  NGL Energy
Partners LP
(Parent)(1)
  NGL Energy
Finance Corp.
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

LIABILITIES AND EQUITY

                                     

CURRENT LIABILITIES:

                                     

Accounts payable—trade

  $   $   $ 1,333,780   $ 11,244   $   $ 1,345,024  

Accounts payable—affiliates

            85,237     70         85,307  

Accrued expenses and other payables

    554     19,021     186,226     12,681         218,482  

Advance payments received from customers

            105,597     508         106,105  

Current maturities of long-term debt

            5,004     58         5,062  
                           

Total current liabilities

    554     19,021     1,715,844     24,561         1,759,980  

LONG-TERM DEBT, net of current maturities

   
250,000
   
850,000
   
1,085,155
   
252,196
   
   
2,437,351
 

OTHER NONCURRENT LIABILITIES

            35,160     4,358         39,518  

EQUITY

   
 
   
 
   
 
   
 
   
 
   
 
 

Partners' equity (deficit)

    1,746,060     (1,876 )   1,745,450     579,312     (2,322,813 )   1,746,133  

Accumulated other comprehensive loss

            (1 )   (72 )       (73 )

Noncontrolling interests

                    568,770     568,770  
                           

Total equity (deficit)

    1,746,060     (1,876 )   1,745,449     579,240     (1,754,043 )   2,314,830  
                           

Total liabilities and equity

  $ 1,996,614   $ 867,145   $ 4,581,608   $ 860,355   $ (1,754,043 ) $ 6,551,679  
                           
                           

(1)
The parent is a co-issuer of the 2019 Notes and 2021 Notes that are included in the NGL Energy Finance Corp. column.

F-130


Table of Contents


NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)


NGL ENERGY PARTNERS LP
Condensed Consolidating Balance Sheet
(U.S. Dollars in Thousands)

 
  March 31, 2014  
 
  NGL Energy
Partners LP
(Parent)(1)
  NGL Energy
Finance Corp.
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

ASSETS

                                     

CURRENT ASSETS:

                                     

Cash and cash equivalents

  $ 1,181   $   $ 8,728   $ 531   $   $ 10,440  

Accounts receivable—trade, net of allowance for doubtful accounts

            887,789     13,115         900,904  

Accounts receivable—affiliates

            7,445             7,445  

Inventories

            306,434     3,726         310,160  

Prepaid expenses and other current assets

            80,294     56         80,350  
                           

Total current assets

    1,181         1,290,690     17,428         1,309,299  

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation

   
   
   
764,014
   
65,332
   
   
829,346
 

GOODWILL

            1,105,008     1,998         1,107,006  

INTANGIBLE ASSETS, net of accumulated amortization

    1,169     11,552     700,603     1,632         714,956  

INVESTMENTS IN UNCONSOLIDATED ENTITIES

            189,821             189,821  

NET INTERCOMPANY RECEIVABLES (PAYABLES)

    327,281     437,714     (720,737 )   (44,258 )        

INVESTMENTS IN CONSOLIDATED SUBSIDIARIES

    1,447,502         17,673         (1,465,175 )    

OTHER NONCURRENT ASSETS

            16,674     121         16,795  
                           

Total assets

  $ 1,777,133   $ 449,266   $ 3,363,746   $ 42,253   $ (1,465,175 ) $ 4,167,223  
                           
                           

F-131


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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

 
  March 31, 2014  
 
  NGL Energy
Partners LP
(Parent)(1)
  NGL Energy
Finance Corp.
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

LIABILITIES AND EQUITY

                                     

CURRENT LIABILITIES:

                                     

Accounts payable—trade

  $   $   $ 726,252   $ 13,959   $   $ 740,211  

Accounts payable—affiliates

            73,703     3,143         76,846  

Accrued expenses and other payables

    554     14,266     124,923     1,947         141,690  

Advance payments received from customers

            29,891     74         29,965  

Current maturities of long-term debt

            7,058     22         7,080  
                           

Total current liabilities

    554     14,266     961,827     19,145         995,792  

LONG-TERM DEBT, net of current maturities

   
250,000
   
450,000
   
929,754
   
80
   
   
1,629,834
 

OTHER NONCURRENT LIABILITIES

            9,663     81         9,744  

EQUITY

   
 
   
 
   
 
   
 
   
 
   
 
 

Partners' equity (deficit)

    1,526,579     (15,000 )   1,462,691     22,994     (1,470,449 )   1,526,815  

Accumulated other comprehensive loss

            (189 )   (47 )       (236 )

Noncontrolling interests

                    5,274     5,274  
                           

Total equity (deficit)

    1,526,579     (15,000 )   1,462,502     22,947     (1,465,175 )   1,531,853  
                           

Total liabilities and equity

  $ 1,777,133   $ 449,266   $ 3,363,746   $ 42,253   $ (1,465,175 ) $ 4,167,223  
                           
                           

(1)
The parent is a co-issuer of the 2021 Notes that are included in the NGL Energy Finance Corp. column.

F-132


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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)


NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Operations
(U.S. Dollars in Thousands)

 
  Three Months Ended September 30, 2014  
 
  NGL Energy
Partners LP
(Parent)(1)
  NGL Energy
Finance Corp.
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

REVENUES

  $   $   $ 5,325,186   $ 55,364   $ (24 ) $ 5,380,526  

COST OF SALES

   
   
   
5,161,935
   
17,554
   
(24

)
 
5,179,465
 

OPERATING COSTS AND EXPENSES:

   
 
   
 
   
 
   
 
   
 
   
 
 

Operating

            84,300     17,253         101,553  

General and administrative

            36,360     5,279         41,639  

Depreciation and amortization

            38,999     11,100         50,099  
                           

Operating Income

            3,592     4,178         7,770  

OTHER INCOME (EXPENSE):

   
 
   
 
   
 
   
 
   
 
   
 
 

Earnings of unconsolidated entities

            2,310     1,387         3,697  

Interest expense

    (4,067 )   (13,134 )   (9,956 )   (1,506 )   12     (28,651 )

Other, net

            (524 )   (81 )   (12 )   (617 )
                           

Income (Loss) Before Income Taxes

    (4,067 )   (13,134 )   (4,578 )   3,978         (17,801 )

INCOME TAX (PROVISION) BENEFIT

   
   
   
1,951
   
(29

)
 
   
1,922
 

EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES

   
(15,157

)
 
   
604
   
   
14,553
   
 
                           

Net Income (Loss)

    (19,224 )   (13,134 )   (2,023 )   3,949     14,553     (15,879 )

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER

                           
(11,056

)
 
(11,056

)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

                           
(3,345

)
 
(3,345

)
                           

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS

  $ (19,224 ) $ (13,134 ) $ (2,023 ) $ 3,949   $ 152   $ (30,280 )
                           
                           

(1)
The parent is a co-issuer of the 2019 Notes and 2021 Notes.

F-133


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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)


NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Operations
(U.S. Dollars in Thousands)

 
  Three Months Ended September 30, 2013  
 
  NGL Energy
Partners LP
(Parent)
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

REVENUES

  $   $ 1,546,226   $ 47,735   $ (24 ) $ 1,593,937  

COST OF SALES

   
   
1,445,442
   
43,432
   
(24

)
 
1,488,850
 

OPERATING COSTS AND EXPENSES:

   
 
   
 
   
 
   
 
   
 
 

Operating

        52,979     2,790         55,769  

General and administrative

        14,089     223         14,312  

Depreciation and amortization

        23,970     1,091         25,061  
                       

Operating Income

        9,746     199         9,945  

OTHER INCOME (EXPENSE):

   
 
   
 
   
 
   
 
   
 
 

Interest expense

    (4,179 )   (6,880 )   (13 )   12     (11,060 )

Other, net

        528     (97 )   (12 )   419  
                       

Income (Loss) Before Income Taxes

    (4,179 )   3,394     89         (696 )

INCOME TAX PROVISION

   
   
(236

)
 
   
   
(236

)

EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES

   
3,238
   
80
   
   
(3,318

)
 
 
                       

Net Income (Loss)

    (941 )   3,238     89     (3,318 )   (932 )

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER

                     
(2,451

)
 
(2,451

)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

                     
(9

)
 
(9

)
                       

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS

  $ (941 ) $ 3,238   $ 89   $ (5,778 ) $ (3,392 )
                       
                       

F-134


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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)


NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Operations
(U.S. Dollars in Thousands)

 
  Six Months Ended September 30, 2014  
 
  NGL Energy
Partners LP
(Parent)(1)
  NGL Energy
Finance Corp.
  Guarantor
Subsidiaries
  Non-
Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

REVENUES

  $   $   $ 8,952,772   $ 76,421   $ (53 ) $ 9,029,140  

COST OF SALES

   
   
   
8,676,881
   
36,690
   
(53

)
 
8,713,518
 

OPERATING COSTS AND EXPENSES:

   
 
   
 
   
 
   
 
   
 
   
 
 

Operating

            150,919     18,502         169,421  

General and administrative

            64,124     5,388         69,512  

Depreciation and amortization

            77,545     11,929         89,474  
                           

Operating Income (Loss)

            (16,697 )   3,912         (12,785 )

OTHER INCOME (EXPENSE):

   
 
   
 
   
 
   
 
   
 
   
 
 

Earnings of unconsolidated entities

            4,875     1,387         6,262  

Interest expense

    (8,313 )   (21,280 )   (18,058 )   (1,517 )   23     (49,145 )

Other, net

            (1,056 )   71     (23 )   (1,008 )
                           

Income (Loss) Before Income Taxes

    (8,313 )   (21,280 )   (30,936 )   3,853         (56,676 )

INCOME TAX (PROVISION) BENEFIT

   
   
   
993
   
(106

)
 
   
887
 

EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES

   
(50,886

)
 
   
337
   
   
50,549
   
 
                           

Net Income (Loss)

    (59,199 )   (21,280 )   (29,606 )   3,747     50,549     (55,789 )

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER

                           
(20,437

)
 
(20,437

)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

                           
(3,410

)
 
(3,410

)
                           

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS

  $ (59,199 ) $ (21,280 ) $ (29,606 ) $ 3,747   $ 26,702   $ (79,636 )
                           
                           

(1)
The parent is a co-issuer of the 2019 Notes and 2021 Notes.

F-135


Table of Contents


NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Operations
(U.S. Dollars in Thousands)

 
  Six Months Ended September 30, 2013  
 
  NGL Energy
Partners LP
(Parent)
  Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

REVENUES

  $   $ 2,914,531   $ 65,421   $ (58 ) $ 2,979,894  

COST OF SALES

        2,735,890     56,094     (58 )   2,791,926  

OPERATING COSTS AND EXPENSES:

                               

Operating

        99,710     5,104         104,814  

General and administrative

        32,297     469         32,766  

Depreciation and amortization

        46,000     1,785         47,785  
                       

Operating Income

        634     1,969         2,603  

OTHER INCOME (EXPENSE):

                               

Interest expense

    (8,368 )   (13,309 )   (28 )   23     (21,682 )

Other, net

        627     (135 )   (23 )   469  
                       

Income (Loss) Before Income Taxes

    (8,368 )   (12,048 )   1,806         (18,610 )

INCOME TAX BENEFIT

        170             170  

EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES

    (10,206 )   1,672         8,534      
                       

Net Income (Loss)

    (18,574 )   (10,206 )   1,806     8,534     (18,440 )

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER

                      (4,139 )   (4,139 )

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

                      (134 )   (134 )
                       

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS

  $ (18,574 ) $ (10,206 ) $ 1,806   $ 4,261   $ (22,713 )
                       
                       

F-136


Table of Contents


NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)


NGL ENERGY PARTNERS LP
Condensed Consolidating Statements of Comprehensive Income (Loss)
(U.S. Dollars in Thousands)

 
  Three Months Ended September 30, 2014  
 
  NGL Energy
Partners LP
(Parent)(1)
  NGL Energy
Finance Corp.
  Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

Net income (loss)

  $ (19,224 ) $ (13,134 ) $ (2,023 ) $ 3,949   $ 14,553   $ (15,879 )

Other comprehensive income (loss)

            4     (26 )       (22 )
                           

Comprehensive income (loss)

  $ (19,224 ) $ (13,134 ) $ (2,019 ) $ 3,923   $ 14,553   $ (15,901 )
                           
                           

(1)
The parent is a co-issuer of the 2019 Notes and 2021 Notes.

 
  Three Months Ended September 30, 2013  
 
  NGL Energy
Partners LP
(Parent)
  Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

Net income (loss)

  $ (941 ) $ 3,238   $ 89   $ (3,318 ) $ (932 )

Other comprehensive loss

            (5 )       (5 )
                       

Comprehensive income (loss)

  $ (941 ) $ 3,238   $ 84   $ (3,318 ) $ (937 )
                       
                       

F-137


Table of Contents


NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)


NGL ENERGY PARTNERS LP
Condensed Consolidating Statements of Comprehensive Income (Loss)
(U.S. Dollars in Thousands)

 
  Six Months Ended September 30, 2014  
 
  NGL Energy
Partners LP
(Parent)(1)
  NGL Energy
Finance Corp.
  Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

Net income (loss)

  $ (59,199 ) $ (21,280 ) $ (29,606 ) $ 3,747   $ 50,549   $ (55,789 )

Other comprehensive income (loss)

            189     (26 )       163  
                           

Comprehensive income (loss)

  $ (59,199 ) $ (21,280 ) $ (29,417 ) $ 3,721   $ 50,549   $ (55,626 )
                           
                           

(1)
The parent is a co-issuer of the 2019 Notes and 2021 Notes.

 
  Six Months Ended September 30, 2013  
 
  NGL Energy
Partners LP
(Parent)
  Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

Net income (loss)

  $ (18,574 ) $ (10,206 ) $ 1,806   $ 8,534   $ (18,440 )

Other comprehensive loss

            (30 )       (30 )
                       

Comprehensive income (loss)

  $ (18,574 ) $ (10,206 ) $ 1,776   $ 8,534   $ (18,470 )
                       
                       

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Cash Flows
(U.S. Dollars in Thousands)

 
  Six Months Ended September 30, 2014  
 
  NGL Energy
Partners LP
(Parent)(1)
  NGL Energy
Finance Corp.
  Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidated  

OPERATING ACTIVITIES:

                               

Net cash provided by (used in) operating activities

  $ (8,180 ) $ (15,383 ) $ (56,019 ) $ 17,947   $ (61,635 )

INVESTING ACTIVITIES:

   
 
   
 
   
 
   
 
   
 
 

Purchases of long-lived assets

            (81,710 )   (1,141 )   (82,851 )

Acquisitions of businesses, including acquired working capital, net of cash acquired

            (657,514 )   (1,250 )   (658,764 )

Cash flows from commodity derivatives

            4,327         4,327  

Proceeds from sales of assets

            8,741         8,741  

Investments in unconsolidated entities

            (6,106 )   (20,284 )   (26,390 )

Distributions of capital from unconsolidated entities           

            2,774     1,875     4,649  
                       

Net cash used in investing activities

            (729,488 )   (20,800 )   (750,288 )
                       

FINANCING ACTIVITIES:

                               

Proceeds from borrowings under revolving credit facilities

            1,923,500     56,000     1,979,500  

Payments on revolving credit facilities

            (1,766,000 )   (38,000 )   (1,804,000 )

Issuance of notes

        400,000             400,000  

Payments on other long-term debt

            (4,173 )   (2 )   (4,175 )

Debt issuance costs

    (269 )   (7,209 )   (1,720 )       (9,198 )

Contributions

    395                 395  

Distributions to owners

    (111,008 )               (111,008 )

Distributions to noncontrolling interest partners

                (8,654 )   (8,654 )

Proceeds from sale of common units, net of offering costs

    370,446                 370,446  

Net changes in advances with consolidated entities

    (249,724 )   (377,408 )   632,995     (5,863 )    
                       

Net cash provided by financing activities

    9,840     15,383     784,602     3,481     813,306  
                       

Net increase (decrease) in cash and cash equivalents           

    1,660         (905 )   628     1,383  

Cash and cash equivalents, beginning of period

    1,181         8,728     531     10,440  
                       

Cash and cash equivalents, end of period

  $ 2,841   $   $ 7,823   $ 1,159   $ 11,823  
                       
                       

(1)
The parent is a co-issuer of the 2019 Notes and 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Cash Flows
(U.S. Dollars in Thousands)

 
  Six Months Ended September 30, 2013  
 
  NGL Energy
Partners LP
(Parent)
  Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidated  

OPERATING ACTIVITIES:

                         

Net cash provided by (used in) operating activities

  $ (8,312 ) $ (44,607 ) $ 4,175   $ (48,744 )

INVESTING ACTIVITIES:

   
 
   
 
   
 
   
 
 

Purchases of long-lived assets

        (37,180 )   (30,219 )   (67,399 )

Acquisitions of businesses, including acquired working capital, net of cash acquired

    (334,085 )   (56,237 )   (2,283 )   (392,605 )

Cash flows from commodity derivatives

        (19,074 )       (19,074 )

Proceeds from sales of assets

        2,223     1     2,224  
                   

Net cash used in investing activities

    (334,085 )   (110,268 )   (32,501 )   (476,854 )
                   

FINANCING ACTIVITIES:

                         

Proceeds from borrowings under revolving credit facility

        1,061,500         1,061,500  

Payments on revolving credit facility

        (893,000 )       (893,000 )

Proceeds from borrowings on other long-term debt

        780     100     880  

Payments on other long-term debt

        (4,499 )   (8 )   (4,507 )

Debt issuance costs

    (133 )   (2,085 )       (2,218 )

Contributions

    504         1,940     2,444  

Distributions to owners

    (60,258 )       (365 )   (60,623 )

Proceeds from sale of common units, net of offering costs

    415,089             415,089  

Net changes in advances with consolidated entities

    (11,459 )   (15,123 )   26,582      
                   

Net cash provided by financing activities

    343,743     147,573     28,249     519,565  
                   

Net increase (decrease) in cash and cash equivalents

    1,346     (7,302 )   (77 )   (6,033 )

Cash and cash equivalents, beginning of period

        11,206     355     11,561  
                   

Cash and cash equivalents, end of period

  $ 1,346   $ 3,904   $ 278   $ 5,528  
                   
                   

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 15—Subsequent Events

Water Solutions Facility Acquisitions

        As described in Note 4, we are party to a development agreement that provides us a right to purchase water disposal facilities developed by the other party to the agreement. During October and November 2014, we purchased five facilities under this development agreement and paid $52.2 million of cash for these facilities.

Sale of Natural Gas Liquids Terminal

        In November 2014, we reached an agreement to sell one of our natural gas liquids terminals. We expect the sale to close in December 2014. We expect to record during the three months ending December 31, 2014 a loss on disposal of approximately $29.0 million, consisting of a loss of $21.0 million on property, plant and equipment and $8.0 million of allocated goodwill.

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REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

NGL Energy Partners LP, the sole member of High Sierra Energy GP, LLC

        We have audited the accompanying consolidated balance sheets of High Sierra Energy GP, LLC and subsidiaries (collectively, the "Company") as of December 31, 2011 and 2010, and the related consolidated statements of operations, equity and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with auditing standards generally accepted in the United States of America as established by the American Institute of Certified Public Accountants. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of High Sierra Energy GP, LLC and subsidiaries as of December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Denver, Colorado
September 4, 2012

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High Sierra Energy GP, LLC and Subsidiaries

Consolidated Balance Sheets

 
  Audited
as of
December 31,
   
 
 
  Unaudited
as of
March 31,
2012
 
 
  2011   2010  
 
  (in thousands)
 

Assets

                   

Current assets

                   

Cash and cash equivalents ($29 at December 31, 2010(1))

  $ 20,187   $ 18,671   $ 11,828  

Accounts receivable, net

                   

Trade ($29,716 at December 31, 2012(1))

    266,806     212,667     299,547  

Affiliate

    476         819  

Inventory, net ($7,140 at December 31, 2010(1))

    94,971     59,272     77,831  

Fair value of derivative instruments

    4,481     2,327     5,946  

Prepaids and other current assets ($3,227 at December 31, 2010(1))

    15,759     20,301     15,395  

Assets of operations held for sale

    8,667     178,310     3,055  
               

Total current assets

    411,347     491,548     414,421  
               

Property, plant and equipment, net

    118,445     89,689     122,077  

Goodwill

    111,314     67,009     111,314  

Other intangible assets, net

    29,806     18,650     27,803  

Other long-term assets

    9,352     559     8,521  
               

Total non-current assets

    268,917     175,907     269,715  
               

Total assets

  $ 680,264   $ 667,455   $ 684,136  
               
               

Liabilities and equity

                   

Current liabilities

                   

Borrowings under lines of credit ($8,374 at December 31, 2010(1))

  $   $ 23,090   $  

Current portion of debt

    11,315     525     11,085  

Accounts payable

                   

Trade ($20,296 at December 31, 2010(1))

    297,522     216,070     318,463  

Affiliates

    6,732     935     7,951  

Accrued liabilities and other ($3,069 at December 31, 2010(1))

    25,787     22,056     17,127  

Fair value of derivative instruments

    1,451     1,199     1,580  

Liabilities of operations held for sale

    376     113,370     369  
               

Total current liabilities

    343,183     377,245     356,575  
               

Long-term debt, net of current portion

    104,088     29,022     101,369  

Other long-term liabilities

    4,726     4,584     4,560  
               

Total non-current liabilities

    108,814     33,606     105,929  
               

Total liabilities

    451,997     410,851     462,504  
               

Commitments and contingencies

                   

Equity

   
 
   
 
   
 
 

Members' equity in High Sierra Energy GP, LLC

    5,728     5,567     5,596  

Noncontrolling common limited partner interests in High Sierra Energy, LP

    221,036     222,105     214,811  

Noncontrolling subordinated limited partner interests in High Sierra Energy, LP

    876     845     708  

Noncontrolling interests in subsidiaries of High Sierra Energy, LP

    607     28,067     497  

Accumulated other comprehensive income

    20     20     20  
               

Total equity

    228,267     256,604     221,632  
               

Total liabilities and equity

  $ 680,264   $ 667,455   $ 684,136  
               
               

(1)
Amounts in parentheses represent consolidated amounts attributable to a former variable interest entity.

   

The accompanying notes are an integral part of these consolidated financial statements.

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High Sierra Energy GP, LLC and Subsidiaries

Consolidated Statements of Operations

 
  Audited for the Years
Ended December 31,
  Unaudited for the
Three Months
Ended March 31,
 
 
  2011   2010   2009   2012   2011  
 
  (in thousands)
 

Revenues

                               

Product, transportation, fees and other

  $ 2,981,821   $ 2,144,674   $ 1,648,512   $ 796,974   $ 654,988  

Unrealized gains (losses) on commodity derivative instruments

    4,917     (3,919 )   88     1,194     872  
                       

Total revenues

    2,986,738     2,140,755     1,648,600     798,168     655,860  

Operating costs and expenses

                               

Product and transportation expenses

    2,856,010     2,050,159     1,523,605     760,646     633,852  

Operating expenses

    48,976     34,644     43,354     15,393     9,252  

General and administrative expenses

    22,116     20,224     23,971     8,408     4,837  

Gain on sale of assets

    (436 )   (851 )   (453 )   (48 )   (22 )

Depreciation and amortization expense

    21,066     17,905     18,144     5,584     4,614  
                       

Total operating costs and expenses

    2,947,732     2,122,081     1,608,621     789,983     652,533  
                       

Operating income

    39,006     18,674     39,979     8,185     3,327  

Other income (expense)

                               

Interest income

    26     25     226     12     67  

Interest expense

    (10,043 )   (5,769 )   (6,023 )   (2,791 )   (1,750 )

Loss from equity method investments

        (1,454 )   (2,436 )        

Other income (expense), net

    3,310     (372 )   2,753     8     (181 )
                       

Income from continuing operations before income taxes

    32,299     11,104     34,499     5,414     1,463  

Income tax expense (benefit)

    (903 )   (1,568 )   2,118     338     1,215  
                       

Income from continuing operations

    33,202     12,672     32,381     5,076     248  

Discontinued operations

                               

Income (loss) from discontinued operations, net

    (3,133 )   (24,649 )   (51,120 )   (5,582 )   2,483  

Loss on disposal of discontinued operations, net

    (6,350 )   (3,913 )       (1,654 )    
                       

Income (loss) from discontinued operations, net

    (9,483 )   (28,562 )   (51,120 )   (7,236 )   2,483  
                       

Net income (loss)

  $ 23,719   $ (15,890 ) $ (18,739 ) $ (2,160 ) $ 2,731  
                       
                       

Net income (loss) attributable to members' equity in High Sierra Energy GP, LLC

  $ 429   $ 63   $ 987   $ (39 ) $ 26  

Net income (loss) attributable to noncontrolling common limited partner interests in High Sierra Energy, LP

    21,111     (17,168 )   (25,224 )   (2,151 )   1,284  

Net income (loss) attributable to noncontrolling interests in subsidiaries of High Sierra Energy, LP

    2,179     1,215     5,498     30     1,421  
                       

Net income (loss)

  $ 23,719   $ (15,890 ) $ (18,739 ) $ (2,160 ) $ 2,731  
                       
                       

Income (loss) from continuing operations attributable to members' equity in High Sierra Energy GP, LLC

  $ 614   $ 525   $ 2,008   $ 106   $ 4  

Income (loss) from continuing operations attributable to noncontrolling common limited partner interests in High Sierra Energy, LP

    30,223     5,450     24,789     4,940     216  

Income (loss) from continuing operations attributable to noncontrolling interests in subsidiaries of High Sierra Energy, LP

    2,365     6,697     5,584     30     28  
                       

Income (loss) from continuing operations

  $ 33,202   $ 12,672   $ 32,381   $ 5,076   $ 248  
                       
                       

Income (loss) from discontinued operations attributable to members' equity in High Sierra Energy GP, LLC

  $ (185 ) $ (462 ) $ (1,021 ) $ (145 ) $ 22  

Income (loss) from discontinued operations attributable to noncontrolling common limited partner interests in High Sierra Energy, LP

    (9,112 )   (22,618 )   (50,013 )   (7,091 )   1,068  

Income (loss) from discontinued operations attributable to noncontrolling interests in subsidiaries of High Sierra Energy, LP

    (186 )   (5,482 )   (86 )       1,393  
                       

Income (loss) from discontinued operations

  $ (9,483 ) $ (28,562 ) $ (51,120 ) $ (7,236 ) $ 2,483  
                       
                       

   

The accompanying notes are an integral part of these consolidated financial statements.

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High Sierra Energy GP, LLC and Subsidiaries

Consolidated Statements of Equity

Years Ended December 31, 2011, 2010 and 2009 (audited) and
Three Months Ended March 31, 2012 (unaudited)

 
  Members'
Equity in
High Sierra
Energy GP, LLC
  Noncontrolling
Common
Limited Partner
Interests in
High Sierra
Energy, LP
  Noncontrolling
Subordinated
Limited Partner
Interests in
High Sierra
Energy, LP
  Noncontrolling
Interests in
Subsidiaries of
High Sierra
Energy, LP
  Accumulated
Other
Comprehensive
Income
  Total  

Balance at January 1, 2009

  $ 8,089   $ 290,617   $ 55   $ 7,962   $ 20   $ 306,743  

Contributions

        5                 5  

Contributions to variable interest entity

                4,145         4,145  

Distributions

    (2,302 )   (33,407 )       (4,178 )       (39,887 )

Vesting of subordinated units

        699     (699 )            

Common units issued for business combinations

        15,696                 15,696  

Unit based awards, net

            954             954  

Comprehensive income

                                   

Net income (loss)

    987     (25,224 )       5,498         (18,739 )
                                     

Total comprehensive income (loss)

                                  (18,739 )
                           

Balance at December 31, 2009

  $ 6,774   $ 248,386   $ 310   $ 13,427   $ 20   $ 268,917  

Contributions

                2,465         2,465  

Distributions

    (1,270 )   (9,257 )       (8,240 )       (18,767 )

Fair value of noncontrolling interest acquired(1)

                19,200         19,200  

Vesting of subordinated units

        144     (144 )            

Unit based awards, net

            679             679  

Comprehensive income (loss)

                                   

Net income (loss)

    63     (17,168 )       1,215         (15,890 )
                                     

Total comprehensive income (loss)

                                  (15,890 )
                           

Balance at December 31, 2010

  $ 5,567   $ 222,105   $ 845   $ 28,067   $ 20   $ 256,604  

Contributions

        10,010                 10,010  

Distributions

    (268 )   (6,589 )       (2,829 )       (9,686 )

Noncontrolling interests acquired(2)

        (24,245 )       (11,701 )       (35,946 )

Noncontrolling interests sold(3)

                (15,109 )       (15,109 )

Fair value of units reacquired in settlement

        (1,986 )               (1,986 )

Vesting of subordinated and restricted units

        630     (630 )            

Unit based awards, net

            661             661  

Comprehensive income (loss)

                                   

Net income (loss)

    429     21,111         2,179         23,719  
                                     

Total comprehensive income (loss)

                                  23,719  
                           

Balance at December 31, 2011

  $ 5,728   $ 221,036   $ 876   $ 607   $ 20   $ 228,267  

Contributions

                         

Distributions

    (93 )   (4,397 )       (140 )       (4,630 )

Unit based awards, net

        323     (168 )           155  

Comprehensive income (loss)

                                   

Net income (loss)

    (39 )   (2,151 )       30         (2,160 )
                                     

Total comprehensive income (loss)

                                  (2,160 )
                           

Balance at March 31, 2012

  $ 5,596   $ 214,811   $ 708   $ 497   $ 20   $ 221,632  
                           
                           

(1)
Fair value of acquired noncontrolling interest in Monroe Gas Storage Company, LLC. See Note 4—Business Combinations.

(2)
Noncontrolling interests in Anticline and Petro Source Products acquired. See Note 4—Business Combinations.

(3)
Noncontrolling interests in Asgard and Monroe sold in 2011. See Note 5—Discontinued Operations, Dispositions and Held for Sale.

   

The accompanying notes are an integral part of these consolidated financial statements.

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High Sierra Energy GP, LLC and Subsidiaries

Consolidated Statements of Cash Flows

 
  Audited for the Years
Ended December 31,
  Unaudited for the
Three Months
Ended
March 31,
 
 
  2011   2010   2009   2012   2011  
 
  (in thousands)
 

Cash flows from operating activities

                               

Net income (loss)

  $ 23,719   $ (15,890 ) $ (18,739 ) $ (2,160 ) $ 2,731  

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

                               

Depreciation, amortization and accretion

    21,385     24,041     23,856     5,603     4,855  

Bad debt expense (recovery)

    1,152     1,871     1,254     (39 )   (71 )

Loss from equity method investments

        1,454     2,436          

Unit-based compensation

    661     679     954     155     122  

Change in fair value of derivative instruments, net

    (4,373 )   9,164     (1,740 )   (959 )   (2,313 )

Gain on previously held equity investment of consolidated subsidiary

        (5,436 )            

Gain on units reacquired in settlement

    (1,986 )                

Loss on disposals of discontinued operations

    6,350     3,913         1,654      

Gain on sale of assets

    (436 )   (1,050 )   (307 )   (48 )   (22 )

Impairment of assets

        20,000     47,366     5,393      

Changes in assets and liabilities:

                               

Accounts receivable

    (49,836 )   (40,182 )   (52,370 )   (33,445 )   (36,766 )

Inventory

    (36,039 )   (3,263 )   (21,948 )   17,160     (1,433 )

Prepaids and other assets

    13,521     (13,765 )   23,429     (925 )   847  

Accounts payable, accrued liabilities and other

    88,681     22,075     87,774     14,267     47,162  
                       

Net cash provided by operating activities

    62,799     3,611     91,965     6,656     15,112  
                       

Cash flows from investing activities

                               

Cash obtained upon consolidation of subsidiary

        1,708              

Cash paid for acquisitions of businesses and noncontrolling interests

    (123,885 )               (33,515 )

(Increase) decrease in restricted cash

    (2,961 )   (1,579 )   (500 )       3,407  

Investment in certificates of deposit

            (10,000 )        

Proceeds upon redemption of certificates of deposit

        2,000     8,000          

Proceeds from disposals of discontinued operations

    35,758     4,450              

Investment in equity method investees

            (23,274 )        

Proceeds from sale of assets

    1,119     9,520     1,707     91     324  

Purchases of property, plant and equipment

    (33,070 )   (17,262 )   (11,757 )   (7,451 )   (8,005 )
                       

Net cash used in investing activities

    (123,039 )   (1,163 )   (35,824 )   (7,360 )   (37,789 )
                       

Cash flows from financing activities

                               

Borrowings on lines of credit

    61,184     114,549     47,873         15,804  

Repayments on lines of credit

    (104,213 )   (102,647 )   (51,074 )       (58,833 )

Borrowings on notes payable

            2,561          

Payments of principal on notes payable

    (1,030 )       (5,247 )       (2,605 )

Borrowings on short-term notes and line of credit—PS Products

    4,915     36,719     42,113         4,915  

Repayments of short-term notes and line of credit—PS Products

    (13,289 )   (28,345 )   (42,113 )       (13,289 )

Borrowings of long-term debt

    145,079         1,237         72,500  

Payments on long-term debt

    (31,612 )   (7,484 )   (1,235 )   (2,821 )   (750 )

(Increase) decrease in cash restricted for debt service

    6,793     (6,793 )            

Refund (deposits) to collateralize letters of credit, net

    3,215     (3,215 )           3,215  

Deferred financing fees for credit facilities

    (11,022 )   (65 )           (5,130 )

Distributions to non-controlling interest holders in subsidiaries of High Sierra Energy, LP

    (2,829 )   (8,240 )   (4,178 )   (140 )   (2,609 )

Contributions from non-controlling interest holders in subsidiaries of High Sierra Energy, LP

        2,465             79  

Partner contributions in variable interest entity capital

            4,145          

Payments to affiliate

    (138 )   (1,090 )   (142 )       (133 )

Distributions to partners of High Sierra Energy, LP

    (6,723 )   (9,892 )   (35,626 )   (4,490 )   (133 )

Contributions from partners of High Sierra Energy, LP

    10,010         5          
                       

Net cash provided by (used in) financing activities

    60,340     (14,038 )   (41,681 )   (7,451 )   13,031  
                       

Net (decrease) increase in cash and cash equivalents

    100     (11,590 )   14,460     (8,155 )   (9,646 )

Cash and cash equivalents, beginning of period

    20,101     31,691     17,231     20,201     20,101  
                       

Cash and cash equivalents, end of period (including $14, $1,430, $0, $218 and $3,091 cash and cash equivalents of subsidiaries held for sale)

  $ 20,201   $ 20,101   $ 31,691   $ 12,046   $ 10,455  
                       
                       

Supplemental disclosure of cash and non-cash activities

                               

Cash paid for interest, net of amount capitalized

  $ 9,234   $ 8,817   $ 4,773   $ 1,793   $ 3,603  

Cash paid for income taxes

        308     974          

Common units issued for business combinations

            15,696          

   

The accompanying notes are an integral part of these consolidated financial statements.

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Notes to the Consolidated Financial Statements

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 1—Organization and Basis of Presentation

Organization

        High Sierra Energy GP, LLC is a Colorado limited liability company that was formed and commenced operations in 2004. As used in these financial statements, the term "the Company" refers to High Sierra Energy GP, LLC and its subsidiaries, unless the context indicates otherwise. The Company owns a 2% general partner interest in High Sierra Energy, LP ("HSE" or the "Partnership"), which is a Delaware limited partnership that was formed and began operations in 2004. The Company also owns a 98% interest in High Sierra Shared Services, LLC, a Colorado limited liability company. The Company has no significant revenue-generating operations other than its ownership interest in the Partnership.

        The Partnership was formed in 2004 to operate similar to a Master Limited Partnership and conducts its operations through its primary operating subsidiaries, which have offices or facilities located in Colorado, Florida, Kansas, Oklahoma, Texas, Wyoming, Minnesota, Illinois, New Mexico, Pennsylvania, Louisiana, North Dakota, and in the Province of Alberta, Canada.

        The Partnership, through its subsidiaries, is engaged in identifying, acquiring, managing, and integrating revenue generating assets in the oil and gas industry, primarily in connection with the transportation, treatment and disposal of oil and natural gas wastewater and the transportation and marketing of crude oil and natural gas liquids. The Partnership also leases well head compressor equipment under operating leases.

Basis of Consolidation and Presentation

        High Sierra Energy GP, LLC consolidates all subsidiaries in which it has a controlling financial interest, including the Partnership. All significant intercompany transactions have been eliminated. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP").

        The accompanying unaudited condensed consolidated financial statements as of March 31, 2012 and for the three months ended March 31, 2012 and 2011 have been prepared in accordance with GAAP for interim consolidated financial information and in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC"). The unaudited condensed consolidated financial statements include all adjustments that management considers necessary for a fair presentation of the financial position and results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed consolidated financial statements do not include all the information and notes required by GAAP for complete annual consolidated financial statements. However, we believe that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

        The accompanying consolidated financial statements include the Company, High Sierra Shared Services, LLC, the Partnership, and all of the Partnership's controlled subsidiaries, which include: High Sierra Energy Operating, LLC ("Operating"), High Sierra Finance Corp., High Sierra Energy Marketing, LLC ("HS Marketing"), High Sierra Crude Oil and Marketing, LLC ("HSCOM"),

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 1—Organization and Basis of Presentation (Continued)

Centennial Energy, LLC ("Centennial") and its Canadian subsidiary Centennial Gas Liquids, ULC ("CGL"), High Sierra Water Services, LLC ("HS Water"), High Sierra Water Holdings ("Water Holdings"), High Sierra Compression, LLC ("HS Compression"), High Sierra Water Services MidContinent, LLC (f/k/a/ National Coal County, LLC—"NCC"), High Sierra Transportation, LLC ("HS Transport"), Petro Source Transportation, LLC ("PS Transport"), High Sierra Ethanol, LLC ("Ethanol"), Greensburg Oil, LLC (d/b/a Nicholas Services—("Nicholas")), High Sierra Terminaling, LLC ("Terminaling"),High Sierra Monroe, LLC ("HS Monroe"), High Sierra Storage, LLC ("HS Storage"), and High Sierra Sertco, LLC ("Sertco"). During 2010, Sierra Asphalt Roofing Company, LLC ("Sarco") was merged into Terminaling. In addition, Petro Source Products, LLC ("PS Products"), a prior variable interest entity in which the Partnership was the primary beneficiary, which was purchased in March 2011, is included in the consolidated financial statements (See Note 6—Variable Interest Entity).

        Investments in entities over which the Partnership has significant influence but not control are accounted for by the equity method and reported within long-term assets. As more fully discussed in Note 4—Business Combinations, HS Storage owned a 70% equity interest in Monroe Gas Storage Company, LLC ("Monroe"), a natural gas storage business, which was accounted for using the equity method of accounting until March 1, 2010. On March 1, 2010, HS Monroe became the manager and operator of Monroe and as a result the Partnership began reporting Monroe on a consolidated basis as of that date until the sale of Monroe in May 2011. The Partnership also owned a 50% equity interest in Bell Gas Gathering, LLC ("Bell Gas"), which was accounted for using the equity method of accounting until the sale of Bell Gas in 2009.

Noncontrolling Interests in Consolidated Subsidiaries

        As the general partner of the Partnership, the Company has the right to control the Partnership. The equity of the Partnership's limited partners is reported as Noncontrolling limited partner interests in High Sierra Energy, LP in the accompanying Consolidated Balance Sheets and Consolidated Statements of Equity.

        The Partnership has an 80% controlling interest in High Sierra Sertco, LLC ("Sertco"). The Partnership had a 75% controlling interest in Asgard Energy, LLC ("Asgard") until Asgard was sold in October 2011, a 60% controlling interest in AntiCline Disposal, LLC ("AntiCline") until the purchase of all of Anticline's membership interest not owned by the Partnership in March 2011, a 70% controlling interest in Monroe until Monroe was sold in May 2011 and a 75% interest in Redwood Resources Marketing, LLC ("Redwood") until Redwood was dissolved in 2009. In addition, until the purchase of all of PS Products' membership interests in March 2011, although it did not directly own a membership interest in PS Products, the Partnership was the primary beneficiary in, and consolidated PS Products, as further discussed in Note 6—Variable Interest Entity. Interests in subsidiaries held by other parties are reported as Noncontrolling interests in the accompanying consolidated financial statements. The noncontrolling interest amounts reported from 2012 relate to Sertco. The noncontrolling interest amounts reported for 2011 and 2010 relate to AntiCline, Asgard, Monroe,

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 1—Organization and Basis of Presentation (Continued)

Sertco, and PS Products. The noncontrolling interest amounts reported for 2009 relate to AntiCline, Asgard, Sertco, PS Products and Redwood.

        During 2009, among other changes as more fully described in Note 12—Goodwill and Intangible Assets, the Partnership's interest in AntiCline decreased from 75% to 60% as provided for in AntiCline's Amended and Restated Limited Liability Company Agreement, as amended, due to the attainment of certain technological and operational criteria with Anticline's discharge water treatment plant. As more fully described in Note 13—Investments in Unconsolidated Affiliate, the Partnership's interest in Monroe increased to 70% from 50% during 2009 as a result of additional cash investments by the Partnership.

Discontinued Operations and Held for Sale

        During 2011, the Partnership committed to a plan to sell its interests in Terminaling, and completed the sale of its membership interests in Asgard and Monroe. During 2010, as more fully described in Note 5—Discontinued Operations, Dispositions and Held for Sale, the Partnership adopted plans to sell its interests in Asgard, NCC and Monroe, and completed the sale of certain assets of Ethanol and NCC. As a result, assets and liabilities of Asgard, Terminaling and Monroe are reported within Assets of operations held for sale and Liabilities of operations held for sale at the lower of their carrying values or fair value less estimated costs to sell in the Consolidated Balance Sheets. The operating results of Asgard, Ethanol, NCC, Monroe and Terminaling, and the combined net loss on the disposals of Asgard, Ethanol, NCC and Monroe are reported within Discontinued Operations in the accompanying Consolidated Statements of Operations. Terminalling was sold in May 2012. See Note 5—Discontinued Operations.

Merger with NGL Energy Partners

        On June 19, 2012, High Sierra Energy GP, LLC completed a merger with NGL Energy Holdings LLC whereby High Sierra Energy GP, LLC became a wholly-owned subsidiary of NGL Energy Holdings LLC. Concurrent with this merger, High Sierra Energy, LP completed a merger with NGL Energy Partners LP, whereby High Sierra Energy, LP became a wholly-owned subsidiary of NGL Energy Partners LP.

Note 2—Significant Accounting Policies

Use of Estimates

        The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and the reported amounts of revenues and expenses for the reporting period. Significant estimates are made with respect to, among other things, determining the fair value of derivative instruments; evaluating impairments of long-lived assets, intangible assets, goodwill and equity investments; determining the fair value of net assets resulting from business combinations, including previously held equity interests and

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 2—Significant Accounting Policies (Continued)

noncontrolling interests; determining the fair value of assets and liabilities held for sale; the measurement and recognition of compensation expense associated with equity compensation awards; estimating accruals related to the self-funded portion of the employee health insurance benefit plan; estimating revenue and expense accruals; establishing estimated useful lives of long-lived assets; estimating asset retirement obligations; and determining liabilities, if any, associated with legal contingencies. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents

        Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of 90 days or less at acquisition. The Company continually monitors its positions and the credit quality of the financial institutions with which it invests and believes that its credit risk related to cash and cash equivalents is minimal. During the years ended December 31, 2011 and 2010 and the three months ended March 31, 2012, the Company has maintained balances in various operating accounts in excess of federally insured limits. The Company has not experienced any losses associated with these amounts.

Restricted Cash

        In connection with the development of Monroe's natural gas storage facility, the Company had certain cash accounts which were restricted to funding construction costs and/or to servicing Monroe's debt obligations. As of December 31, 2010 restricted cash balances, all of which were reported in "Assets of operations held for sale" consisted of the following (in thousands):

Restricted Cash—Short Term
  December 31,
2010
 

Debt Service Reserve Account

  $ 6,793  

Capital Expenditure Reserve Account

    4,232  

Operating Expenditure Reserve Account

    125  

        These restricted cash balances were held at one financial institution, and were in excess of FDIC insurance limits as of December 31, 2010.

Accounts Receivable, Accounts Payable and Offsetting Amounts Related to Certain Contracts

        Certain accounts receivable, accounts payable and derivative assets and liabilities are presented on a net basis where a right of offset exists. The Company also offsets amounts of cash collateral held by the Company or deposited with counterparties arising from certain derivative instruments executed with the same counterparty under a master netting agreement against the fair value amounts reported for those derivative instruments.

        Credit risk is the risk of loss that the Company would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. The Company grants credit in the

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 2—Significant Accounting Policies (Continued)

normal course of business to customers in the United States and Canada and maintains credit policies with regard to its counterparties that management believes prudently manages overall credit risk. These policies include an evaluation of a counterparties' financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements for the netting of positive and negative exposures associated with a single counterparty.

        Management periodically reviews accounts receivable and reduces the carrying amount by an allowance for doubtful accounts that reflects management's best estimate of the amount that may not be collectible. Allowances for doubtful accounts receivable are based on available information and historical collection experience, including how recently payments have been received. The Company expenses trade receivables (i) on a general basis when a receivable reaches a certain age and (ii) on a specific identification basis when a receivable is no longer deemed collectible. Although the allowance for doubtful accounts is considered adequate, actual amounts collected could vary significantly from reported amounts.

Inventory

        Inventory consists primarily of (i) natural gas liquids ("NGL"), mostly propane, butane and natural gasoline, (ii) asphalt flux and (iii) crude oil. Volumes held for immediate sale or exchange are reported as a current asset and are valued at the lower of cost or market, with cost determined using a weighted average cost method within the specific inventory pools. Transportation costs related to purchases are included in inventory.

        At the end of each reporting period, an assessment of the carrying value of inventories is performed and any adjustments necessary to reduce the carrying value to lower of cost or market value are made.

Property, Plant and Equipment

        Property, plant and equipment are stated at cost. Costs associated with asset purchases and/or improvements that expand existing capacity or lengthen the asset's estimated useful life are capitalized. Repairs and maintenance expenditures incurred in order to maintain the day-to-day operation of existing assets that do not extend the estimated useful lives of the related assets are charged to expense as incurred. Interest cost incurred on borrowings related to construction in progress during the construction period is also capitalized. Property, plant or equipment acquired as a result of a business combination is initially recorded at estimated fair value.

        Leasehold improvements are amortized over the shorter of the improvement's estimated useful life or the lease term.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 2—Significant Accounting Policies (Continued)

        Depreciation is provided using the straight-line method over the estimated useful lives of depreciable assets, as follows:

Asset Class
  Depreciable
Lives
(years)

Railcars, transportation vehicles and equipment

  5 to 10

Injection wells and equipment

  3 to 30

Buildings, terminals, and improvements

  6 to 30

Software

  3

Asset Retirement Obligations

        An asset retirement obligation ("ARO") is a legal obligation associated with the retirement of a tangible long-lived asset that generally results from the acquisition, construction, development or normal operation of the asset. The Company recognizes the fair value of an ARO as an addition to the cost of the related asset in the period incurred when a reasonable estimate of the amount can be made. Significant inputs used to estimate an ARO include: (i) the expected retirement date; (ii) the estimated costs of retirement, including adjustments for cost inflation and the time value of money; and (iii) the appropriate method for allocation of estimated asset retirement costs to expense. The cost for asset retirement is capitalized as part of the cost of the related long-lived assets and subsequently allocated to expense over the remaining useful lives of the assets associated with the obligation. The ARO liability accretes to the estimated total retirement obligation over the period the related assets are used through the expected retirement date.

Goodwill

        Goodwill represents the cost of an acquisition less the fair value of the net assets of the acquired business. The Company evaluates goodwill for impairment as of the end of August of each year and on an interim basis whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Goodwill is tested for impairment at a level of reporting referred to as a "reporting unit." A reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management.

        Impairment testing of goodwill is a two-step process. The first step, used to identify potential impairment, compares the estimated fair value of the reporting unit with its book carrying amount, including goodwill, using a probability weighted discounted cash flow approach. When the estimated fair value is greater than book carrying value, the reporting unit's goodwill is not impaired. Conversely, if the book carrying value is greater than estimated fair value, a second step is performed to determine the amount of impairment. The second step compares the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying value of goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the fair value is recognized

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 2—Significant Accounting Policies (Continued)

as an impairment loss. The implied fair value of goodwill is an estimate of the amount of goodwill that would be recognized if the reporting unit was acquired as of the impairment test date.

        During the year ended December 31, 2010 the Company recognized an impairment of the goodwill in Terminaling, which is reported in "Discontinued operations—Loss from discontinued operations, net" in the Consolidated Statements of Operations. During the year ended December 31, 2009, the Company recognized an impairment of the goodwill in NCC which is reported in "Discontinued operationsLoss from discontinued operations, net" in the Consolidated Statements of Operations. See Note 8—Fair Value—Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis and Note 12—Goodwill and Intangible Assets for further information and disclosures.

Intangible Assets

        The Company recognizes specifically identifiable intangible assets when specific rights and contracts are acquired. As more fully described in Note 12—Goodwill and Intangible Assets, all of the Company's intangible assets, other than goodwill, have finite lives and are amortized on a straight-line basis over their estimated useful lives, ranging from 4 to 25 years. Costs to renew or extend such contracts are not significant, and are expensed as incurred. The Partnership's intangible assets consist of customer contracts and relationships, patents, certain acquired permits and, prior to the sale of Monroe, Monroe's pad gas lease and tax abatement agreement which were held for sale as disclosed in Note 5—Discontinued Operations, Dispositions and Held for Sale.

        The Company tests intangible assets for impairment whenever events or circumstances indicate that the carrying value may not be recoverable. The Company recognized impairments on certain intangible assets held and used by Monroe and Terminaling during the year ended December 31, 2010, and NCC during the year ended December 31, 2009. The impairment charges for discontinued operations are reported within "Discontinued operations—Loss from discontinued operations, net." See Note 5—Discontinued Operations, Dispositions and Held for Sale, Note 8—Fair Value—Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis and Note 12—Goodwill and Intangible Assets for further information.

Impairment of Long-Lived Assets

        The Company reviews its long-lived assets, including intangible assets subject to amortization, to evaluate whether there has been an other than temporary impairment when certain events or changes in circumstances indicate that the carrying amount of the assets may not be recovered. The Company evaluates the carrying value of its long-lived assets at the business unit level. The carrying value of a long-lived asset group is considered to be unrecoverable when the undiscounted cash flows expected to result from the use and eventual disposition of the asset group are less than the asset group's carrying value. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset group is recognized. The

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 2—Significant Accounting Policies (Continued)

Company considers various factors when determining if long-lived assets should be evaluated for impairment, including but not limited to:

        The Company also periodically evaluates its investments in unconsolidated affiliates for impairment. An impairment of an investment in an unconsolidated affiliate results when factors indicate that the investment's fair value is less than its carrying value and the reduction in value is other than temporary.

        The Company recognized impairments on certain long-lived assets of Terminalling during the three months ended March 31, 2012, Monroe and Terminaling during the year ended December 31, 2010, and NCC during the year ended December 31, 2009. The impairment charges for discontinued operations are reported within "Discontinued operations—Loss from discontinued operations, net." See Note 5—Discontinued Operations, Dispositions and Held for Sale, Note 8—Fair Value and Note 12—Goodwill and Intangible Assets for further information.

Deferred Financing Costs

        Deferred financing costs are amortized over the estimated lives of the related obligations or, in certain circumstances, accelerated if the obligation is refinanced or extinguished, on a straight-line basis, which approximates the effective interest method. Deferred financing costs are reported within Other long-term assets in the Consolidated Balance Sheets.

Fair Value of Financial Instruments

        Management believes that the carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value due to the short-term maturity of these instruments. The carrying amount of the amounts outstanding under the Company's credit facilities, notes payable, long-term debt and interest rate swap agreements approximate fair value primarily due to their variable interest rates that management believes approximate current borrowing rates, and their

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 2—Significant Accounting Policies (Continued)

short-term duration. Derivative instruments are recorded at fair value based on available market information.

        The fair value guidance defines fair value, establishes a framework for measuring fair value, establishes a three-level valuation hierarchy for disclosure of fair value measurements and expands the disclosures about fair value. A financial instrument's categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The determination of fair values incorporates various factors, including the credit standing of the counterparties and the impact of credit enhancements (such as cash deposits and letters of credit). Assessment of the significance of a particular input to the fair value measurement requires judgment and considers factors specific to the asset or liability.

        Fair value for financial instruments classified as Level 1 within the fair value hierarchy is based on unadjusted quoted prices for these contracts in highly liquid, active markets.

        Fair value for financial instruments classified as Level 2 is based on pricing methodologies that use market prices for comparable actively traded contracts, pricing interpolated from recent trades of similar contracts, models using highly observable inputs, such as commodity options, forward prices and volatilities observable in active markets for the full term of the instruments.

        Fair value for financial instruments classified as Level 3 is estimated using inputs requiring significant management judgment or estimation, and often requires the use of complex and subjective internal models and forecasts. Whenever possible, the Partnership uses market data that market participants would use when pricing an asset or liability. In addition to the unobservable inputs, Level 3 financial instruments typically include observable inputs that are not actively quoted or cannot be validated to external sources.

        The methods described above may result in a fair value that may not be indicative of net realizable value or of future fair values. While the Company believes that its valuation methods are appropriate and consistent with those of other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value.

        See Note 7—Risk Management Activities and Derivative Instruments and Note 8—Fair Value for the related disclosures regarding the Company's financial derivative instruments.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

        Rather than on an ongoing basis, certain assets and liabilities are measured to fair value on a nonrecurring basis when certain circumstances or events occur. These circumstances or events include but are not limited to fair value adjustments arising from impairments of long-lived assets, as a result of business combinations or a decision to hold assets for sale.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 2—Significant Accounting Policies (Continued)

Risk Management Activities and Derivative Instruments

        The Company's primary business activities expose it to market risk from changes in commodity prices, which could cause variability in the Company's earnings and cash flows. The Company uses a variety of derivative instruments, both financial and physical based, to minimize the effects of commodity price fluctuations. Although the Company generally adopts a strategy of risk reduction through matching of physical purchases with a corresponding physical market sale, the Company's risk reduction strategy also includes the use of derivative contracts. Monroe's variable rate borrowings exposed the Company to interest rate risk from changes in Monroe's variable borrowing rate, which could have resulted in volatility in the Company's interest expense and cash interest paid. The Company used interest rate swaps for a portion of the variable rate borrowings to mitigate the effects of changes in Monroe's variable interest borrowing rate until May 2011 when the interest rate swap agreements were terminated in connection with the sale of the Company's interest in Monroe.

        Interest on the Company's current borrowings as further described in Note 15—Debt under its High Sierra Credit Facility are at variable interest rates. The Company has elected not to use derivatives to mitigate the risk of interest rate changes on its interest expense and related cash flows for interest.

        Derivative instruments, unless the instruments qualify for and an election has been made to apply normal purchase normal sale accounting, are reported at their fair value in the Consolidated Balance Sheets as assets or liabilities. The Company discloses the fair value of substantially all of its derivative instruments separate from other assets and liabilities under the caption Fair value of derivative instruments in the accompanying Consolidated Balance Sheets.

        Changes in the fair value of derivative instruments, including physically delivered derivatives for which the Company has not elected normal purchase normal sale accounting, are reported in the Consolidated Statements of Operations in the period that they occur within the financial statement line related to the item economically hedged by the instrument. Realized and unrealized gains and losses on derivative instruments are reported within either Revenues or Interest expense. Revenue gains or losses relate to instruments used to hedge the cash flow associated with the sale and purchase of products. Interest expense gains or losses related to interest rate swap agreements used to manage the interest rate risk associated with Monroe's variable interest borrowings. Changes in risk management activities are reported in cash flows from operating activities in the Company's Consolidated Statements of Cash Flows.

        The Company has determined that substantially all of its forward physical commodity purchase and sale agreements, with certain exceptions, qualify for the normal purchase normal sale accounting. Revenues and costs of purchases associated with these contracts are recognized on the accrual basis of accounting on the date of sale or purchase, respectively.

Deferred Gain on Sale Leaseback Transaction

        The Company amortizes deferred gains on the sale and leaseback of railcar equipment under operating leases on a straight-line basis over the related lease terms. The amortization of these gains is

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 2—Significant Accounting Policies (Continued)

reported as a reduction to the related rent expense. See Note 20—Commitments and Contingencies—Sale Leaseback Transaction for additional information.

Revenue Recognition

        Revenues from sales of crude oil, NGL, water and other hydrocarbon products are recognized on a gross basis at the time title to the product sold transfers to the purchaser and collection of those amounts is reasonably assured. Sales or purchases with the same counterparty that are entered into in contemplation of one another are reported on a net basis as one transaction. Revenue from wastewater disposal trucking services is recognized when the wastewater is picked up from the customer's location, and in other cases upon delivery of the wastewater to a specific delivery location, depending upon the terms of the contractual agreements. Revenue from other transportation services is recognized upon completion of the services as defined in the customer agreement. Revenue on equipment leased under operating leases is billed and recognized monthly according to the terms of the related lease agreement with the customer over the term of the lease. Net gains and losses resulting from commodity derivative instruments are recognized within revenues.

        Revenues for the wastewater disposal business are recognized upon delivery of the wastewater to the disposal facilities. Certain agreements require customers to deliver minimum quantities of wastewater for an agreed upon period. Revenue is recognized when the wastewater is delivered, with an adjustment for the minimum volume delivery in the event that actual delivered wastewater is less than the committed minimum. Revenues from crude oil condensate recovered from wastewater are recognized upon delivery to the customer.

        Revenues from Monroe's firm natural gas storage reservation agreements provided for a fixed monthly capacity reservation fee payable regardless of the actual capacity utilized, and were recognized ratably over the terms of the related storage agreements. Firm storage revenues for the use of injection and withdrawal services based on the volume of natural gas nominated for injection or withdrawal were recognized as the volumes are nominated. Hub service revenues, including "park and loan" services, were recognized in revenue as the services were provided.

        Amounts billed to customers for shipping and handling costs are included in Revenues in the Consolidated Statements of Operations. Shipping and handling costs associated with product sales are included in Operating expenses in the Consolidated Statements of Operations. Taxes collected from customers and remitted to the appropriate taxing authority are excluded from Revenues in the Consolidated Statements of Operations.

Revenue and Expense Accruals

        The Company routinely makes accruals based on estimates for both revenues and expenses due to the amount of time required to receive third party information, compile billing information and reconcile the Company's records with those of its third party customers and vendors. Information that is delayed includes, among others, actual volumes purchased, transported or sold, adjustments to inventory and invoices for purchases, actual product deliveries, and other operating expenses. The

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 2—Significant Accounting Policies (Continued)

Company makes accruals that report these items at their estimated amounts based on internal records and information from third parties. Estimated accruals are reversed in the following month when actual information has been received from third parties and reconciled to the Company's internal records.

Foreign Currency Translation

        The functional currency of the Partnership's Canadian subsidiary, CGL, is the US dollar. As of January 1, 2009, CGL had cumulative translation adjustments of $20,000 which will remain in accumulated other comprehensive income until the entity is sold or dissolved.

Comprehensive Income

        Other than net income (loss), the Company had no other sources of comprehensive income for the three months ended March 31, 2012 and for the years ended December 31, 2011, 2010 and 2009.

Business Combinations

        Transactions or events in which the Company acquires a controlling financial interest in a business are accounted for under the acquisition method. The identifiable assets, liabilities, any previously held equity interest and any noncontrolling interests are recorded at their estimated fair values as of the business combination date. The excess of consideration paid over the fair value of the net assets acquired, if any, is recognized as goodwill.

Equity Method of Accounting

        Investments in the equity of entities where the Company has significant influence, but not a controlling financial interest or a variable interest in which the Company is not the primary beneficiary, were accounted for under the equity method of accounting. The Company has no equity method investees as of March 31, 2012, December 31, 2011, and December 31, 2010. The assets or liabilities of equity investees are not consolidated. The Company's share of the net income or loss of its equity investees is reported as one line item in the Consolidated Statements of Operations, and increases or decreases, as applicable, the carrying value of the Company's investments in equity investees in its Consolidated Balance Sheets. Contributions from the Company to these investees increase the carrying value of the Company's investment. Distributions to the Company from these investees reduce the carrying value of the Company's investment. Both contributions to and distributions from investees involving the Company are reported within Investing Activities in the Consolidated Statements of Cash Flows.

Accounting for Changes in Ownership Interests in Subsidiaries or Equity Investees

        The Company's ownership interest in a consolidated subsidiary may change if the Company sells a portion of its interest, purchases a portion of the subsidiary's interest not owned by the Company, or if the subsidiary issues new equity or repurchases equity. If the transaction does not result in a change in the Company's controlling financial interest in the subsidiary and is not deemed a sale of real estate,

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 2—Significant Accounting Policies (Continued)

the transaction is accounted for as an equity transaction. If the transaction results in a change in controlling financial interest, it is accounted for as a business combination at fair value where control is acquired, or as a sale and deconsolidation where control is relinquished.

        In March 2011, the Partnership acquired all of the noncontrolling membership interests of Anticline and PS Products. These acquisitions did not result in a change in the Partnership's controlling interest in these subsidiaries and were accounted for within equity.

        In March 2010, the Partnership acquired a controlling financial interest in Monroe, a previously held equity investee, which was accounted for as a business combination. See Note 4—Business Combinations for a description of this event and its effect on the consolidated financial statements.

Income Taxes

        The Company and the Partnership have elected to be treated as partnerships for federal and state income tax purposes within the United States ("U.S."). As such, the Company does not directly pay U.S. federal income taxes, but does pay taxes in certain states that are accounted for as income taxes. The Company's U.S. taxable income or loss, which may vary substantially from the net income or loss reported in the accompanying Consolidated Statements of Operations, is includable in the income tax returns of the Company's members and the Partnership's partners. However, the Partnership's wholly-owned Canadian subsidiary CGL is taxable in Canada. The income tax expense or benefit reported in the Consolidated Statements of Operations represents Canadian income taxes on CGL's taxable income.

        The Company accounts for income taxes using the asset and liability method. Deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their bases for income tax purposes, capital loss carryforwards and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed, and if it is more likely than not that a portion or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to their estimated net realizable value. Deferred tax amounts expected to be settled within the next twelve months are classified as current, and all other deferred tax amounts are classified as long term in the accompanying Consolidated Balance Sheets.

        To account for uncertainty in income taxes, the Company applies a "more likely than not" recognition threshold and measurement attribute to the financial statement recognition and measurement of an income tax position taken or expected to be taken in an income tax return. The Company records penalties related to income tax items as a component of general and administrative expenses, and interest expense related to income tax items as a component of interest expense.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 2—Significant Accounting Policies (Continued)

Other Taxes

        The Company is subject to other taxes assessed by various governmental authorities such as goods and services tax, sales and use tax, utility users' tax, business franchise taxes, and Propane Education Research Council assessments. The Company records these taxes within Operating costs and expenses in the accompanying Consolidated Statements of Operations.

Unit-Based Compensation

        Equity classified unit-based compensation cost is measured at fair value, based on the estimated fair value of the common unit at the grant date, and is recognized as expense over the vesting period. The Company estimates the fair value of units granted using prices paid by third parties for the same instrument, or values disclosed in financial statements filed with the Securities and Exchange Commission by an investor on or nearest to the grant date adjusted for various factors including voting rights, the lack of liquidity, the existence of minority interests and distribution rights.

Note 3—Recently Issued Accounting Pronouncements

        The following outlines the recent guidance that is applicable to the Company and has or may have an impact on the consolidated financial statements and related disclosures:

Fair Value Measurements and Disclosures

        In May 2011, the Financial Accounting Standards Board amended the accounting guidance for fair value measurement and disclosure. The amended guidance was intended to associate the fair value measurement and disclosure requirements under GAAP with those under International Financial Reporting Standards. The amendment primarily clarifies the application of the existing guidance and provides for increased disclosures, particularly related to Level 3 fair value measurements. The amended guidance became effective for the Company prospectively as of January 1, 2012. The adoption of the amended guidance did not have a material effect on the Company's consolidated financial statements.

Intangibles—Goodwill and Other

        In September 2011, the FASB amended the accounting guidance for goodwill impairment testing. The amended guidance provides an entity with an option to first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. This guidance became effective for the Company as of January 1, 2012. The adoption of the amended guidance did not have a material effect on the Company's consolidated financial statements.

        In December 2010 the FASB has issued an update to its guidance regarding goodwill impairment testing for reporting units with zero or negative carrying amounts. For those reporting units, "Step 2" of the goodwill impairment test is required if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, the guidance

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 3—Recently Issued Accounting Pronouncements (Continued)

requires consideration of qualitative factors that are consistent with the existing guidance and examples, which require that goodwill of a reporting unit be tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. This guidance became effective for the Company on January 1, 2012. The adoption of the amended guidance did not have a material effect on the Company's consolidated financial statements.

Note 4—Business Combinations

        The results of operations for all business combinations are included in the Company's Consolidated Statements of Operations beginning with the date of the business combination. As more fully described in Note 12—Goodwill and Intangible Assets, the purchase price for certain business combinations made prior to 2009 included contingent consideration in the form of subordinated units that are accounted for as additional consideration provided certain vesting conditions are met.

High Sierra Water Services, LLC

        On June 1, 2011, the Partnership acquired substantially all of the wastewater disposal assets of Marcum Midstream 1995-2 Business Trust and Marcum Midstream 1995-EC Holdings, LLC ("Marcum") (the "Marcum Acquisition"), which assets had been operated under the trade name Conquest Water Services ("Conquest"). The Marcum Acquisition was completed in exchange for $85.2 million in cash and, pursuant to two employment agreements which were entered into as part of the acquisition, additional estimated future cash consideration of $1.4 million payable 26 months after the purchase date. The amount of additional cash consideration that may ultimately be paid by the Partnership is based upon a multiple of earnings before interest, income taxes, depreciation and amortization ("EBITDA") less a portion of accumulated capital expenditures for the twelve months ending June 30, 2013, or the twelve months prior to termination of employment, whichever occurs earlier. Subsequent adjustments to the estimated fair value of the additional cash consideration will be reported as a component of operating expenses until ultimate cash settlement of the liability occurs. Changes in the estimated value of this liability, which were $0 and a reduction of $0.2 million for the three months ended March 31, 2012 and the year ended December 31, 2011, respectively, are recorded within Operating expenses in the Consolidated Statement of Operations. The goodwill amount recognized relates primarily to the assembled workforce and expected growth of the business.

        The Marcum Acquisition was funded from an increase in the Company's credit facility and the proceeds from issuance of 385,000 common units in exchange for $10.0 million cash. Information regarding the credit facility is disclosed in Note 15—Debt. Information regarding common units issued is disclosed in Note 17—Partners' Capital and Distributions.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 4—Business Combinations (Continued)

        The recognized amounts of identifiable assets acquired and liabilities assumed, based upon their estimated fair values as of June 1, 2011, were as follows (in thousands):

Other current assets

  $ 259  

Property, plant and equipment

    22,110  

Intangible assets(1)

    20,250  

Goodwill

    44,305  
       

Total assets

    86,924  
       

Accrued liabilities

    104  

Asset retirement obligations

    176  

Deferred compensation liability(2)

    1,431  
       

Total liabilities

    1,711  
       

Net assets acquired

  $ 85,213  
       
       

(1)
Intangible assets consist of customer relationships and non-compete agreements of $20 million and $0.3 million, respectively.

(2)
The estimated fair value of the earnings based future cash consideration at the purchase date. The amount of this liability will increase or decrease based upon a multiple of EBITDA less a portion of capital expenditures. Amounts due are payable in cash on July 30, 2013. As of March 31, 2012 the estimated value of this liability was $1.3 million.

Anticline and Petro Source Products

        On March 16, 2011 the Partnership acquired all of the remaining membership interests in Anticline. The purchase price was $30.0 million. The purchase also included a payment of 40% of the working capital amount in excess of $0.8 million to the former noncontrolling members, which amounted to $2.0 million and was paid in June 2011. In addition a payment in the amount $2.2 million representing distributions due to Anticline's former noncontrolling members was made. Finally the Partnership and Anticline agreed to terminate the existing Royalty Agreement between the parties.

        On March 16, 2011 the Partnership acquired all of the membership interests in PS Products. The purchase price was $6.7 million, which was the amount of equity contributed by, plus accrued interest due to, the previous noncontrolling interest owners. There are no other payments or adjustments related to the purchase of PS Products.

Monroe Gas Storage Company, LLC

        Effective March 1, 2010, HS Monroe became the operator and manager of Monroe, and as a result HS Storage gained a controlling financial interest in Monroe. Monroe is a developer and operator of a natural gas storage facility located in Mississippi. The results of operations of Monroe were consolidated with those of the Partnership beginning March 1, 2010. No cash or other

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 4—Business Combinations (Continued)

consideration was exchanged for Monroe, and no significant transactions costs were incurred. Membership interests in Monroe owned by the Partnership as of the transaction date had a fair value of $44.8 million. The recognized amounts of identifiable assets acquired and liabilities assumed, based upon their fair values as of March 1, 2010, were as follows (in thousands):

Current assets (including cash acquired of $1.7 million)

  $ 6,039  

Long term assets

    142,995  

Intangible customer assets

    128  

Other intangible assets

    22,493  

Non-recourse long-term debt

    (98,412 )

Other liabilities assumed

    (9,243 )
       

Total net assets acquired

  $ 64,000  
       
       

        The Partnership recognized a gain of $5.4 million as a result of remeasuring to fair value its previously held equity investment in Monroe as of the date of the business combination. The fair value of the previously held equity interest was estimated using a weighting of income and market values for similar gas storage companies. The gain was recognized in "Discontinued operationsLoss from discontinued operations, net" in the Consolidated Statement of Operations for the year ended December 31, 2010.

        As discussed further in Note 5—Discontinued Operations, Dispositions and Held for Sale, the Partnership committed to a plan to sell its interest in Monroe effective November 1, 2010, and concluded the sale of its interest in Monroe in May 2011. The Partnership was subsequently notified of claims by the purchaser for alleged breach of representations in the merger agreement. See Note 20—Commitments and Contingencies—Legal Contingencies.

Note 5—Discontinued Operations, Dispositions and Held for Sale

Discontinued Operations

        During 2011, the Partnership committed to plans to dispose of its wholly-owned subsidiary, Terminaling. During 2010, the Partnership committed to plans to dispose of its 75% controlling interest in the business operations of Asgard, the Partnership's wholly-owned subsidiary NCC, and HS Storage's 70% controlling interest in the business operations of Monroe. The Partnership will not and does not have continuing involvement in the operations of Asgard, NCC or Monroe and their operations and cash flows have been eliminated from those of other ongoing operations of the Partnership.

        Terminaling.    Terminaling is held for sale as of December 31, 2011 and March 31, 2012. As discussed further in Note 23—Subsequent Events, the Partnership completed the sale of Terminalling on May 31, 2012. In connection with the sale, the Partnership recognized an impairment of the carrying value of the Teminalling assets of $5.4 million, which is reported in Income (loss) from discontinued operations, net in the Consolidated Statement of Operations for the three months ended March 31, 2012.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 5—Discontinued Operations, Dispositions and Held for Sale (Continued)

        Asgard.    Asgard was held for sale as of December 2010. In October 2011, the Partnership sold its membership interests in Asgard for $6.2 million plus the value of Asgard's derivative contracts of $2.8 million, subject to customary working capital adjustments. The Partnership has been notified of claims by one of Asgard's trading partners, and a similar claim by the purchaser of Asgard, for alleged breach of representation in the purchase and sale agreement. See Note 20—Commitments and Contingencies—Legal Contingencies for additional information.

        Ethanol.    In October 2010, the Partnership sold Ethanol's tangible and intangible assets for approximately $2.3 million. Ethanol was dissolved in November 2010.

        NCC.    Effective December 31, 2010, the Partnership sold substantially all of NCC's tangible and intangible assets to a related party for $2.2 million. In addition, the Partnership agreed to sell an additional land parcel for $300,000, contingent upon providing the buyer with satisfactory title to the land. The land parcel was sold during December 2011. The Partnership was contingently liable for environmental claims asserted by the buyer within 180 days, up to a maximum of $2.2 million as of December 31, 2010. The Partnership accrued an estimated $0.4 million for these contingencies as of December 31, 2010; during 2011, this accrual was released as no environmental liabilities or claims were asserted during the allotted time frame.

        In June 2011, the Partnership entered into a settlement agreement with the former owners from the original acquisition of NCC by the Partnership in which the parties agreed to a full release and dismissal of all claims. In connection with this settlement the former owners of NCC agreed to relinquish all rights, title and interest in their 76,389 Partnership units ("Relinquished Units"). The Partnership received $0.5 million of amounts previously held in escrow, and agreed to pay a total of $0.4 million to the former owners of NCC, contingent upon receipt of satisfactory title to two of NCC's land properties. In addition, in prior years the Partnership had accrued $2.1 million for an estimated settlement related to the acquisition of NCC. As a result of the settlement with the former owners of NCC, the Partnership reversed the entire $2.1 million accrual. The $0.5 million escrow settlement received and the reversal of the accrual were recorded within Other Income (expense)—Other income (loss), net in the accompanying Consolidated Statement of Operations for the year ended December 31, 2011. The Partnership recorded a gain of $2.0 million related to the Relinquished Units as Other Income (expense)—Other income (loss), net in the accompanying Consolidated Statement of Operations for the year ended December 31, 2011.

        Monroe.    Monroe was held for sale as of December 31, 2010. In May 2011, the Partnership sold its 70% membership interest in Monroe for $147.0 million together with a purchase option on land for an adjacent natural gas storage property for $1.0 million, subject to normal working capital adjustments. In connection with the closing, amounts due under the Monroe credit facility and the Monroe Interest Rate Swap agreements aggregating $103.7 million were repaid in full. Cash proceeds received by the Partnership after deductions for a pro rata share of funds held in escrow and transaction costs were $20.9 million. In addition, the Partnership received a $6.8 million repayment of principal and interest loaned to Monroe by the Partnership, and $1.0 million for the sale of an option to purchase a property

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 5—Discontinued Operations, Dispositions and Held for Sale (Continued)

adjacent to the Monroe site. These proceeds, along with other available funds from operations, were used to pay down principal on the Partnership's credit facility term loans.

        In connection with the sale of Monroe a portion of the sales price was held in escrow to provide a general indemnity to the purchaser amounting to $11.6 million, and an additional escrow of $0.5 million to provide for the settlement of customary working capital items. Of the total escrowed amounts, the Partnership was entitled to 70%, with the remaining 30% to Monroe's former noncontrolling interest holders. As of December 31, 2011, the Partnership was in negotiations regarding several working capital items, and had been notified by the purchaser of a claim of breach of representations in the merger agreement. See Note 20—Commitments and Contingencies—Legal Contingencies for additional information. At December 31, 2011, the Partnership had recorded an allowance of approximately $1.9 million on the funds in escrow. Included within Prepaids and other current assets on the accompanying Consolidated Balance Sheet at December 31, 2011 was $6.7 million related to the Partnership's share of the funds in escrow, net of the allowance. In May 2012, the Partnership and the purchaser agreed to a settlement whereby the Partnership would receive approximately $5.0 million of the funds in escrow. The Partnership recorded a loss of $1.7 million, reported within Loss on disposal of discontinued operations in the accompanying Consolidated Statement of Operations for the three months ended March 31, 2012, to reduce the carrying value of the asset to the recoverable amount.

        Redwood.    Redwood was held for sale and was sold in 2008. After the sale of Redwood in 2008, certain assets and liabilities, primarily open inventory positions, were retained. The retained net assets were sold during 2009. Revenues and expenses in 2010 relate to proceeds and expenses associated with the settlement of a legal dispute.

        High Sierra Power Marketing, LLC and Sierra Power Asset Marketing, LLC.    In 2008, the Partnership adopted a plan to discontinue operations of two subsidiaries, High Sierra Power Marketing, LLC ("HS Power") and Sierra Power Asset Marketing, LLC ("Sierra Power") which together comprised the Power Marketing Business group. Neither HS Power nor Sierra Power had remaining assets or liabilities and were dissolved effective December 30, 2009.

        The revenues, net income (loss) and gain (loss) on disposal from these companies reported within Discontinued operations within the accompanying Consolidated Statements of Operations are as follows (in thousands):

 
  Year Ended December 31, 2011  
 
  Asgard(1)   Monroe(2)   NCC   Terminaling   Total  

Revenues

  $ 40,466   $ 5,806   $ 16   $ 6,947   $ 53,235  

Income (loss) from operations(3)

    58     (1,167 )   909     (1,102 )   (1,302 )

Net income (loss)(3)

    58     (15,574 )   1,547     (1,102 )   (15,071 )

Gain (loss) on disposal

    7,475     (14,407 )   582         (6,350 )

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 5—Discontinued Operations, Dispositions and Held for Sale (Continued)


 
  Year Ended December 31, 2010  
 
  Asgard   Ethanol   Monroe   NCC   Redwood   Terminaling   Total  

Revenues

  $ 45,780   $ 688   $ 12,816   $ 11,626   $ 759   $ 20,417   $ 92,086  

Income (loss) from operations

    (2,331 )   2,464     (12,585 )   (6,265 )   695     (9,658 )   (27,680 )

Net income (loss)(3)

    (2,562 )   2,474     (14,482 )   (6,523 )   241     (9,774 )   (30,626 )

Gain (loss) on disposal

        2,034         (5,947 )           (3,913 )

 

 
  Year Ended December 31, 2009  
 
  Asgard   Ethanol   NCC   Redwood   Terminaling   HS Power   Sierra Power   Total  

Revenues

  $ 39,743   $ 861   $ 14,227   $ 7,383   $ 13,972   $ 6   $ 57   $ 76,249  

Income (loss) from operations

    4,534     592     (56,217) (4)   (70 )   (1,097 )   (36 )   57     (52,237 )

Net income (loss)(3)

    4,478     609     (56,795 )   (42 )   (1,256 )   (25 )   95     (52,936 )

 

 
  Three Months Ended March 31, 2012  
 
  Monroe   NCC   Terminaling   Total  

Revenues

  $   $   $ 671   $ 671  

Income (loss) from operations(3)

        (259 )   (5,323 )   (5,582 )

Net income (loss)(3)

    (1,654 )   (259 )   (5,323 )   (7,236 )

Gain (loss) on disposal

    (1,654 )           (1,654 )

 

 
  Three Months Ended March 31, 2011  
 
  Asgard   Monroe   NCC   Terminaling   Total  

Revenues

  $ 23,946   $ 3,494   $ 7   $ 1,737   $ 29,184  

Income (loss) from operations(3)

    2,496     368     (105 )   (301 )   2,458  

Net income (loss)(3)

    2,424     214     (105 )   (368 )   2,165  

Gain (loss) on disposal

                     

(1)
Amounts for Asgard are for the ten month period beginning January 1, 2011, through October 31, 2011, the date Asgard was sold.

(2)
Amounts for Monroe are for the five month period beginning January 1, 2011 through May 31, 2011, the date Monroe was sold.

(3)
Amounts of net income (loss) above include intercompany interest and corporate allocations that are excluded from the Loss from discontinued operations, net reported in the Consolidated Statements of Operations.

(4)
Includes an impairments of $47.4 million.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 5—Discontinued Operations, Dispositions and Held for Sale (Continued)

Held for Sale

        As of March 31, 2012 and December 31, 2011 the assets and liabilities of Terminaling have been reported as held for sale at the lower of their carrying value or estimated fair value less costs to sell. The carrying amounts of the major classes of assets and liabilities were as follows (in thousands):

 
  December 31,
2011
Terminaling
  March 31,
2012
Terminaling
 

Cash and cash equivalents

  $ 14   $ 218  

Trade accounts receivable, net

    468     109  

Inventory

    211     192  

Prepaids and other current assets

    121     76  

Property, plant and equipment, net

    6,595     2,222  

Other intangibles, net

    1,258     238  
           

Total assets of operations held for sale

  $ 8,667   $ 3,055  
           
           

Accounts payable—trade

  $ 110   $ 126  

Accrued liabilities and other current liabilities

    266     243  
           

Total liabilities of operations held for sale

  $ 376   $ 369  
           
           

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 5—Discontinued Operations, Dispositions and Held for Sale (Continued)

        As of December 31, 2010 the assets and liabilities of Asgard and Monroe were reported as held for sale at the lower of their carrying value or estimated fair value less costs to sell. The carrying amounts of the major classes of assets and liabilities were as follows (in thousands):

 
  December 31, 2010  
 
  Asgard   Monroe   Total  

Cash and cash equivalents

  $ 566   $ 864   $ 1,430  

Restricted cash

        11,150     11,150  

Trade accounts receivable, net

    11,322     1,505     12,827  

Inventory

    935         935  

Prepaids and other current assets

    395     403     798  

Property, plant and equipment, net

    2     132,215     132,217  

Other intangibles, net

        11,395     11,395  

Other long-term assets

        7,558     7,558  
               

Total assets of operations held for sale

  $ 13,220   $ 165,090   $ 178,310  
               
               

Borrowings under non-recourse credit facility—current

  $   $ 6,300   $ 6,300  

Accounts payable—trade

    7,217     1,370     8,587  

Accrued liabilities and other current liabilities

    951     1,033     1,984  

Fair value of derivative instruments—current

    1,890     1,361     3,251  

Borrowings under non-recourse credit facility—long term

        89,651     89,651  

Fair value of derivative instruments—non current

    323     1,083     1,406  

Other long term liabilities

        2,191     2,191  
               

Total liabilities of operations held for sale

  $ 10,381   $ 102,989   $ 113,370  
               
               

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 5—Discontinued Operations, Dispositions and Held for Sale (Continued)

Assets and Liabilities of Discontinued Operations Included in Consolidated Balance Sheets

        As of December 31, 2011 and 2010, amounts for NCC that are included in the Consolidated Balance Sheets, but not included in the assets and liabilities of operations held for sale, were as follows (in thousands):

 
  December 31,  
 
  2011   2010  

Cash and cash equivalents

  $ 152   $ 278  

Trade accounts receivable, net

    4     1,504  

Accounts receivable—intercompany

        77  

Prepaids and other current assets

    110     520  

Property, plant and equipment, net

    83     70  
           

Total assets

  $ 349   $ 2,449  
           
           

Accounts payable—trade

  $ 9   $ 2,688  

Accounts payable—affiliates

        19,153  

Accrued liabilities and other current liabilities

    653     1,136  

Other long term liabilities

        392  
           

Total liabilities

    662     23,369  
           

Member equity

    (313 )   (20,920 )
           

Total liabilities and equity

  $ 349   $ 2,449  
           
           

        Remaining activities at NCC are primarily reclamation of a disposal pit property.

Note 6—Variable Interest Entity

Petro Source Products, LLC

        PS Products ("the former VIE") is engaged primarily in the purchase or brokering of condensate, NGLs and crude oil. PS Products sells its products to other third parties and also to a subsidiary of the Partnership, which then sells the products to its third party customers. In March 2011 the Partnership purchased all of the membership interests in PS Products and became the sole member.

        At inception on January 1, 2009, prior to its acquisition by the Partnership, PS Products was financed through member equity contributions and a bank line of credit as more fully described in Note 15—Debt—Petro Source Products Credit Facility. The Partnership did not own PS Products membership interests until March 2011. Some members of PS Products were also common unitholders, officers and/or employees of the Partnership.

        PS Products entered into a Trading Agreement, as amended, (the "Agreement") with the Partnership on January 1, 2009. As defined in the Agreement, the Partnership earned a residual amount of income calculated as the former VIE's gross margin less operating costs and a fixed return

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 6—Variable Interest Entity (Continued)

to its equity members. The former VIE reported net income (loss) of $0.1 million during the period January 1, 2011 through March 16, 2011, and $(1.3) million and $0.5 million for the years ended December 31, 2010 and 2009, respectively. The Partnership earned income and collected cash from PS Products in accordance with the Trading Agreement from January 1, 2009 through March 16, 2011. During the period January 1, 2011 through March 16, 2011, the Partnership earned $0.6 million. For the years ended December 31, 2010 and 2009, the Partnership earned $2.7 million and $2.2 million, respectively. PS Products made no cash distributions to the Partnership during the period January 1, 2011 through March 16, 2011, and $1.25 million and zero cash distributions for the years ended December 31, 2010 and 2009, respectively. The Company eliminates all intercompany transactions in the Company's consolidated financial statements.

Significant Judgments Regarding PS Products

        Prior to purchasing the membership interests of PS Products, the Partnership had determined that it was the primary beneficiary of the former VIE because per the Agreement the former VIE's equity members (i) lacked the right to receive residual returns of PS Products, and (ii) the Partnership was obligated to provide a full indemnity for trading losses, if any, incurred by PS Products. No amounts were incurred or paid under this indemnity, and no financial support was provided to the former VIE by the Partnership from its inception through its acquisition by the Partnership.

Financial Statement Impact of PS Products

        Prior to March 2011, as the primary beneficiary, the Partnership consolidated the former VIE and recognized a noncontrolling interest for PS Products' membership equity. The assets, liabilities and

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 6—Variable Interest Entity (Continued)

operations attributable to PS Products while it was a VIE included in the Partnership's consolidated financial statements were as follows (in thousands):

Balance Sheet
  As of
December 31,
2010
 

Cash and cash equivalents

  $ 29  

Accounts receivable, trade

    29,716  

Accounts receivable intercompany(1)

    25,647  

Inventory

    7,140  

Prepaids and other current assets

    3,227  
       

Total assets

  $ 65,759  
       
       

Borrowings under line of credit

  $ 8,374  

Accounts payable, trade

    20,296  

Accounts payable, intercompany(1)

    30,674  

Accrued liabilities and other

    3,069  
       

Total liabilities

    62,413  

Partner's capital(1)

    3,346  
       

Total liabilities and partners' capital

  $ 65,759  
       
       

(1)
Eliminates in consolidation

Statement of Operations
  For the Period
January 1 -
March 16,
2011
  Year ended
December 31,
2010
  Year ended
December 31,
2009
 

Revenue

  $ 119,518   $ 396,054   $ 150,010  

Operating, product, transportation and general and administrative expenses

    118,414     394,112     146,233  
               

Operating income

    1,104     1,942     3,777  

Interest income and expense, net

    994     3,214     3,304  
               

Net income (loss) attributable to noncontrolling interests

  $ 110   $ (1,272 ) $ 473  
               

Net income (loss) attributable to the Partnership

  $   $   $  
               
               

        Prior to March 2011, the assets of PS Products were the property of the former VIE and were not available to the Partnership for any purpose. The creditors of PS Products had recourse only to the assets of the former VIE, and no recourse to the Partnership's general assets or credit.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 7—Risk Management Activities and Derivative Instruments

Commodity Instruments

        The Partnership's primary risk management objective is to reduce the volatility in its cash flows arising from changes in commodity prices related to future sales or purchases of NGLs, crude oil and, prior to the sale of the Partnership's interest in Asgard, natural gas. Derivative instruments are used to economically hedge exposure to price fluctuations with respect to these commodities. The derivative instruments used consist primarily of swaps traded in over-the-counter markets. The Partnership has mitigated a significant portion of its expected commodity price risk with derivative agreements that expire at various times through March 2013.

        Physical transactions that are derivatives and are ineligible, or become ineligible, for normal purchase normal sale accrual accounting are accounted for as derivative assets or liabilities at fair value, with the changes in fair value recorded net in revenues. Substantially all of the Partnership's physical purchase and sale forward contracts qualify for the normal purchase normal sale election and accordingly are recognized under accrual accounting as the purchases or sales occur.

        The use of commodity derivatives may allow the Partnership to reduce volatility in its realized margins as realized gains or losses on derivative instruments generally are offset by corresponding gains or losses in the Partnership's sales or purchases of physical products. While realized derivative gains and losses are generally expected to be offset by increases or decreases in value of physical sales or purchases, the Partnership's derivative instruments are reported at fair value in the Company's Consolidated Balance Sheets.

        Credit reviews of derivative counterparties are conducted and agreements containing collateral requirements are made when considered necessary. In addition, the Partnership uses standard master netting agreements with several of its counterparties that allow for the offset of positive and negative exposures with its counterparties and offsets the assets and liabilities associated with the fair value of the derivatives with these counterparties, and with amounts related to the Partnership's right to receive or obligation to pay cash collateral.

        The use of derivative instruments may create exposure to the risk of financial loss in certain circumstances, including when (i) NGLs do not trade at historical levels relative to crude oil, (ii) sales volumes are less than expected, requiring market purchases to meet commitments, or (iii) counterparties fail to purchase or deliver contracted commodity quantities or otherwise fail to perform. To the extent the Partnership engages in derivative activities, it may be prevented from realizing the benefits of favorable market price changes in the physical market. However, the Partnership may be similarly insulated against losses resulting from unfavorable changes in market pricing in the physical market.

Position Management Program

        In connection with managing inventory positions and maintaining a constant presence in the marketplace, both necessary for the Partnership's core business, the Partnership has established maximum net open position limits (the sum of the absolute values of all long and short positions for which there is no offsetting purchase or sale within the same product type), a stop loss limit (the

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 7—Risk Management Activities and Derivative Instruments (Continued)

maximum aggregate dollar value of cumulative physical and financial realized and unrealized losses on open positions), and tenor limits (the maximum permitted term of open contract positions). These activities are monitored independently by the Partnership's risk management function and take place within predefined limits and authorizations.

Interest Rate Instruments

        Prior to the sale of Monroe, the Partnership's borrowings included both fixed and variable interest rate debt. Monroe had entered into interest rate swap agreements to manage the interest rate risk associated with its variable rate borrowings, which effectively converted a portion of Monroe's variable interest rate payments to fixed rate interest payments per the agreements. As a result, a portion of Monroe's interest payment cash flows were insulated from the effects of increases in the variable borrowing rate. Conversely, Monroe was similarly prevented from realizing a portion of the benefits of favorable changes in the variable interest borrowing rate.

Financial Statement Impact of Derivative Instruments

        The Partnership does not designate or account for derivatives as either cash flow or fair value hedges. Changes in the fair value of commodity derivatives are reported within revenues each period. Changes in the fair value of interest rate derivatives were reported as a component of interest expense each period. Cash settlements associated with derivative activities are reported as operating cash flows in the Consolidated Statements of Cash Flows.

        The impact of the Partnership's derivative instruments on the Company's Consolidated Balance Sheets and Statements of Operations are summarized below (in thousands):

 
  Derivative Assets
Fair Value As Of
  Derivative Liabilities
Fair Value As Of
 
Derivative contracts and
their location in the
Consolidated Balance Sheets
  December 31,
2011
  December 31,
2010
  March 31,
2012
  December 31,
2011
  December 31,
2010
  March 31,
2012
 

Commodity Contracts

                                     

Fair value of derivative instruments—current

  $ 4,481   $ 2,327   $ 5,946   $ 1,451   $ 3,412   $ 1,580  

Liabilities of operations held for sale

                    (2,213 )    

Interest Rate Contracts

                                     

Fair value of derivative instruments—current

                    2,444      

Liabilities of operations held for sale

                    (2,444 )    
                           

Total

  $ 4,481   $ 2,327   $ 5,946   $ 1,451   $ 1,199   $ 1,580  
                           
                           

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 7—Risk Management Activities and Derivative Instruments (Continued)


 
  Year Ended
December 31,
  Three Months
Ended
March 31,
 
Derivative contracts and the
location of gain or loss in the
Consolidated Statements of Operations
 
  2011   2010   2009   2012   2011  

Revenue: Derivative gain (loss)

                               

Realized gain (loss)

  $ 10,140   $ 6,677   $ 18,349   $ (3,515 ) $ (302 )

Unrealized gain (loss)

    4,373     (7,958 )   1,740     1,194     872  

Interest Expense: Derivative gain (loss)

                               

Realized gain (loss)

        (1,463 )            

Unrealized gain (loss)

        (1,206 )            
                       

    14,513     (3,950 )   20,089     (2,321 )   570  

Discontinued operations(1)

    1,753     4,039     (1,652 )       954  
                       

Total gain (loss)

  $ 16,266   $ 89   $ 18,437   $ (2,321 ) $ 1,524  
                       
                       

(1)
Represents amounts for Asgard and Monroe reported in Discontinued operations—Loss from discontinued operations, net in the Consolidated Statements of Operations.

Outstanding Derivative Contracts

        The following tables provide information on the volume of the Partnership's net outstanding commodity forward derivative purchase and (sales) contracts for positions related to commodity risk as of December 31, 2011 and March 31, 2012 (in thousands):

 
  Volumes (Barrels)  
Commodity
  December 31, 2011   March 31, 2012  

Crude Oil

    (918 )   1,469  

Normal Butane

    253     587  

Propane

    996     619  

Unleaded Gasoline

    (16 )    

Natural Gasoline

    217     33  

Note 8—Fair Value

Fair Value Measurement

        Fair value measurements and disclosures relate principally to the Partnership's derivative positions. For a description of the fair value guidance and the fair value hierarchy, see Note 2—Significant Accounting Polices—Fair Value of Financial Instruments.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 8—Fair Value (Continued)

        The following table presents the gross and net financial instruments that are measured at fair value on a recurring basis at December 31, 2011 and 2010 and at March 31, 2012, and by valuation hierarchy and includes amounts held for sale (in thousands):

As of March 31, 2012
  Derivative
Assets
  Derivative
Liabilities
 

Commodity Contracts

             

Observable inputs—Level 1

  $   $  

Significant other observable inputs—Level 2

    16,830     9,748  

Significant unobservable inputs—Level 3

         
           

    16,830     9,748  

Netting of counterparty contracts under master netting agreements

    (8,168 )   (8,168 )

Cash collateral held or provided with counterparties

    (2,716 )    
           

Total All Contracts

  $ 5,946   $ 1,580  
           
           

 

As of December 31, 2011
  Derivative
Assets
  Derivative
Liabilities
 

Commodity Contracts

             

Observable inputs—Level 1

  $   $  

Significant other observable inputs—Level 2

    9,433     3,546  

Significant unobservable inputs—Level 3

         
           

    9,433     3,546  

Netting of counterparty contracts under master netting agreements

    (1,928 )   (1,928 )

Cash collateral held or provided with counterparties

    (3,024 )   (167 )
           

Total All Contracts

  $ 4,481   $ 1,451  
           
           

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 8—Fair Value (Continued)


As of December 31, 2010
  Assets   Liabilities  

Commodity Contracts

             

Observable inputs—Level 1

  $   $  

Significant other observable inputs—Level 2

    10,416     11,658  

Significant unobservable inputs—Level 3

         
           

    10,416     11,658  

Netting of counterparty contracts under master netting agreements

    (8,085 )   (8,085 )

Cash collateral held or provided with counterparties

    (4 )   (161 )
           

Total Commodity Contracts, net

    2,327     3,412  

Interest Rate Contracts

   
 
   
 
 

Significant other observable inputs—Level 2

        2,444  
           

Total Interest Rate Contracts

        2,444  

Total All Contracts

   
2,327
   
5,856
 

Commodity contracts reported in liabilities held for sale, net

        (2,213 )

Interest rate contracts reported in liabilities held for sale, net

        (2,444 )
           

Total

  $ 2,327   $ 1,199  
           
           

Rollforward of Level 3 Net Liability

        The following table provides a reconciliation of changes in fair value of derivatives measured at fair value using inputs classified as Level 3 in the fair value hierarchy (in thousands):

 
  Year Ended
December 31,
 
 
  2011   2010   2009  

Fair value, beginning of period

  $   $ (145 ) $  

Realized and unrealized gains and (losses)(1)

            (145 )

Transfers In/Out of Level 3, net(2)

        145      
               

Fair value, end of period

  $   $   $ (145 )
               
               

(1)
Gains and losses associated with Level 3 commodity derivatives are reported within revenues and gains and losses associated with Level 3 interest rate derivatives are reported as a component of Interest expense. Unrealized losses on Monroe Level 3 interest rate swaps are reported in Discontinued operations—Loss from discontinued operations, net and are excluded from this schedule

(2)
Transfers out of Level 3 represent existing assets or liabilities that were re-categorized to Level 2 because inputs to the model became observable.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 8—Fair Value (Continued)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

        In June 2011 the Partnership completed the Marcum Acquisition. The transaction was accounted for as a purchase using the acquisition method of accounting, under which the assets and liabilities acquired are accounted for at their fair values on the acquisition date. The fair values of these assets and liabilities were estimated primarily using income and adjusted cost replacement approaches, based on significant unobservable inputs (Level 3). See Note 4—Business Combinations.

        Effective March 1, 2010, the Partnership assumed control over the operations and management of Monroe and as a result, the Partnership acquired a controlling financial interest in Monroe. The Partnership accounted for this event as a business combination using the acquisition method of accounting, which requires that Monroe's assets and liabilities, and the Partnership's previously held equity interest and noncontrolling interest in Monroe, be measured to fair value. The fair values of these assets, liabilities and interests were estimated primarily using income and adjusted cost replacement approaches, based on significant unobservable inputs (Level 3). See Note 4—Business Combinations.

        During 2011, the Partnership committed to a plan to sell the assets of Terminaling and in 2010, the Partnership committed to plans to sell, a fleet of railcars, the assets of NCC, its controlling interest in Asgard and its controlling interest in Monroe. The related assets and liabilities held for sale are reported at the lower of their historical carrying values or estimated fair value less costs to sell, with fair value estimated using a market approach based on significant unobservable inputs (Level 3). See Note 5—Discontinued Operations, Dispositions and Held for Sale.

        In November 2010, certain long-lived assets and intangible assets of Monroe were remeasured to fair value in conjunction with the Partnership's impairment evaluation for long-lived assets associated with the expected sale of Monroe. Property, plant and equipment, intangible assets and the pad gas lease asset with net book values of $144.4 million, $12.4 million and $8.3 million, respectively, were written down to their estimated fair values of $132.2 million, $11.4 million and $7.5 million, respectively, resulting in a total impairment loss of $14.0 million. The fair values of the remaining long-lived assets, which consist of gas storage facilities, related equipment and certain intangible assets were estimated based primarily on an income and market approach using significant unobservable inputs (Level 3) and indications of fair value less costs to sell from prospective buyers (Level 3).

        As of August 2010, certain long-lived assets, intangible assets and the goodwill of Terminaling were remeasured to fair value in conjunction with the Partnership's impairment evaluation for long-lived assets. Property, plant and equipment, intangible assets and goodwill with a net book value of $10.2 million, $2.1 million and $0.7 million, respectively, were written down during 2010 to an estimated fair value of $5.6 million, $1.4 million and zero, respectively, resulting in a total impairment loss of $6.0 million. The fair values of the remaining long-lived assets, which consist of asphalt manufacturing facilities and related equipment, were estimated primarily based on an income and market approach using significant unobservable inputs (Level 3) and indications of value from prospective buyers.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 8—Fair Value (Continued)

        As of August 2009, certain long-lived assets, intangible assets and the goodwill of NCC were remeasured to fair value in conjunction with the Partnership's impairment evaluation for long-lived assets. Property, plant and equipment, intangible assets and goodwill with a net book value of $26.2 million, $5.3 million and $25.3 million, respectively, were written down during 2009 to an estimated fair value of $9.4 million, resulting in an impairment loss of $47.4 million. The fair values of the remaining long-lived assets, which consist of transportation vehicles and related equipment, were estimated based on a market approach using significant unobservable inputs (Level 3).

Note 9—Accounts Receivable

        Receivables consist of the following, including accounts receivable from affiliates (in thousands):

 
  December 31,    
 
 
  March 31,
2012
 
 
  2011   2010  

Accounts receivable

  $ 271,376   $ 229,287   $ 304,063  

Allowance for doubtful accounts

    (3,626 )   (3,793 )   (3,588 )
               

Total accounts receivable, net

    267,750     225,494     300,475  

Assets of operations held for sale

    (468 )   (12,827 )   (109 )
               

Total carrying value in the Consolidated Balance Sheets

  $ 267,282   $ 212,667   $ 300,366  
               
               

        The Partnership accrues unbilled revenue primarily due to timing differences between the delivery of crude oil, natural gas and condensate and the receipt of a delivery statement. The Partnership had $25.5 million and $22.9 million of unbilled revenues as of December 31, 2011 and 2010, respectively. Of these amounts, unbilled revenues included in Assets of operations held for sale were zero and $9.2 million as of December 31, 2011 and 2010, respectively. Unbilled receivables included in Accounts receivable, net were $25.5 million and $13.7 million as of December 31, 2011 and 2010, respectively. The Partnership had $77.6 million of unbilled revenues at March 31, 2012. Unbilled accounts receivable included in Accounts receivable, net were $77.6 million at March 31, 2012.

        The changes in the allowance for doubtful accounts were as follows (in thousands):

 
  Year ended
December 31,
2011
  2010   Three Months
Ended
March 31,
2012
 

Beginning balance allowance for doubtful accounts

  $ 3,793   $ 2,202   $ 3,626  

Additions

    657     1,959     (38 )

Writeoffs and other

    (824 )   (368 )    
               

    3,626     3,793     3,588  

Less: Assets of operations held for sale

    (3,117 )       (3,117 )
               

Ending balance allowance for doubtful accounts

  $ 509   $ 3,793   $ 471  
               
               

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 9—Accounts Receivable (Continued)

        During 2009 the Partnership recovered $3.5 million of accounts receivable that had been reserved in 2008. The recovery was reported within Other income (expense)—Other income (loss), net in the Consolidated Statements of Operations for the year ended December 31, 2009. As discussed further in Note 20—Commitments and Contingencies—Legal Contingencies, the Partnership indemnified the purchaser for loss in the event the purchased claim was subsequently disallowed or impaired. The purchaser made a claim for the indemnity during 2011 at which time the partnership recorded a $2.2 million loss within Other income (expense) —Other income (loss), net in the Consolidated Statements of Operations. See Note 20—Commitments and Contingencies—Legal Contingencies for further discussion regarding this claim.

Note 10—Inventory

        Inventory held for sale or exchange consisted of the following (in thousands):

 
  December 31, 2011   December 31, 2010   March 31, 2012  
 
  Total   Assets of
Operations
Held
For Sale
  Total
Carrying
Value
  Total   Assets of
Operations
Held
For Sale
  Total
Carrying
Value
  Total   Assets of
Operations
Held
For Sale
  Total
Carrying
Value
 

Asphalt flux

  $ 1,571   $ (211 ) $ 1,360   $ 1,938   $   $ 1,938   $ 1,898   $ (192 ) $ 1,706  

Propane

    29,803         29,803     22,900         22,900     12,018         12,018  

Normal butane

    25,864         25,864     16,276         16,276     8,141         8,141  

Natural gas

                935     (935 )                

Natural gasoline

    186         186     172         172     40         40  

Crude oil

    36,618         36,618     17,677         17,677     55,685         55,685  

Other

    1,140         1,140     309         309     241         241  
                                       

Total inventory

  $ 95,182   $ (211 ) $ 94,971   $ 60,207   $ (935 ) $ 59,272   $ 78,023   $ (192 )   77,831  
                                       
                                       

        The Partnership recorded non-cash charges of approximately $1.9 million, $47,000 and $9,000 for the years ended December 31, 2011, 2010 and 2009, respectively, related to the write down of predominantly NGL inventories to the lower of cost or market, primarily as a result of declines in commodity prices during these periods. The Partnership recorded non-cash charges of approximately $1.4 million and $0.1 million for the three months ended March 31, 2012 and 2011, respectively, related to the write down of NGL inventories to the lower of cost or market, primarily as a result of declines in commodity prices during these periods.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 11—Property, Plant and Equipment

        Property, plant and equipment consist of the following (in thousands):

 
  December 31, 2011   December 31, 2010   March 31, 2012  
 
  Total   Assets of
Operations
Held
For Sale
  Total
Carrying
Value
  Total   Assets of
Operations
Held
For Sale
  Total
Carrying
Value
  Total   Assets of
Operations
Held
For Sale
  Total
Carrying
Value
 

Land

  $ 7,104   $ (1,200 ) $ 5,904   $ 4,532   $ (91 ) $ 4,441   $ 7,104   $ (1,200 ) $ 5,904  

Transportation vehicles and equipment

    26,278     (33 )   26,245     20,475     (107 )   20,368     28,188     (24 )   28,164  

Equipment

    86,162     (7,973 )   78,189     116,838     (48,259 )   68,579     84,774     (4,471 )   80,303  

Buildings, terminals, improvements

    33,321     (1,529 )   31,792     103,554     (85,668 )   17,886     32,612     (668 )   31,944  

Software

    5,602         5,602     5,317         5,317     6,340         6,340  

Construction in progress

    10,817         10,817     7,489     (1,339 )   6,150     12,924         12,924  
                                       

    169,284     (10,735 )   158,549     258,205     (135,464 )   122,741     171,942     (6,363 )   165,579  

Accumulated depreciation

    (44,245 )   4,141     (40,104 )   (36,299 )   3,247     (33,052 )   (47,643 )   4,141     (43,502 )
                                       

Total property, plant and equipment

  $ 125,039   $ (6,594 ) $ 118,445   $ 221,906   $ (132,217 ) $ 89,689   $ 124,299   $ (2,222 ) $ 122,077  
                                       
                                       

        Depreciation expense for the years ended December 31, 2011, 2010 and 2009 was $13.4 million, $11.1 million and $14.0 million, respectively. The Partnership capitalizes interest on major projects during construction. For the years ended December 31, 2011, 2010 and 2009 capitalized interest was $154,000, $108,000 and $4,000, respectively. Depreciation expense for the three months ended March 31, 2012 and 2011 was $3.6 million and $ 2.7 million, respectively. For the three months ended March 31, 2012 and 2011, capitalized interest was $106,000 and $0, respectively.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 12—Goodwill and Intangible Assets

Goodwill

        The Company tests its reporting units for impairment of goodwill in the third quarter. See Note 2—Significant Accounting Policies. The change in the carrying amount of goodwill is as follows (in thousands):

 
  Year Ended December 31,   Three Months
Ended
March 31,
2012
 
 
  2011   2010  

Beginning of period

  $ 67,009   $ 67,688   $ 111,314  

Purchase allocations

    44,305          

Impairment

        (679 )    
               

End of period

  $ 111,314   $ 67,009   $ 111,314  
               
               

        As further disclosed in Note 4—Business Combinations, in June 2011 the Partnership completed the Marcum Acquisition. In connection with this acquisition, the Partnership recognized $44.3 million of goodwill.

        Due to unfavorable construction and low demand for asphalt products in Florida, operating profits and cash flows for Terminaling were much lower than expected during 2010, resulting in reduced earnings and cash flow forecasts for Terminaling. Effective August 2010, a goodwill impairment loss of $0.7 million, representing the entire goodwill of Terminaling, was recognized and is reported within Discontinued operations—Loss from discontinued operations, net in the Consolidated Statements of Operations. The fair value of Terminaling was estimated using the expected present value of forecasted future cash flows (Level 3).

        Due to unfavorable commodity prices for natural gas, unfavorably wet weather conditions and increased competition in the water disposal and related water truck transportation business in Oklahoma, operating profits and cash flows for NCC were much lower than expected during 2009, resulting in reduced earnings and cash flow forecasts for NCC. Effective August 2009, a goodwill impairment loss of $25.3 million, representing the entire goodwill of NCC, was recognized and reported within Discontinued operations—Loss from discontinued operations, net in the Consolidated Statements of Operations. The fair value of NCC was estimated using the expected present value of forecasted future cash flows (Level 3).

Contingent Subordinated Units and Additional Goodwill

        As part of the consideration for certain business combinations, the Partnership included in the offering price contingent consideration in the form of subordinated units which vest and convert to common units upon achievement of certain vesting conditions, or are forfeited if the vesting conditions are not met. Depending upon the acquisition agreements, vesting conditions included attainment of certain technological targets or EBITDA targets. These subordinated units convert to common units upon attainment of the vesting conditions. The status of the subordinated unit contingent consideration

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 12—Goodwill and Intangible Assets (Continued)

as of and during the years ended December 31, 2011, 2010 and 2009 and the three months ended March 31, 2012 is as follows (in thousands, except for the number of subordinated units):

 
  Contingent Subordinated
Units
 
 
  Number   Fair Value  

Unvested—December 31, 2008

    1,310,601   $ 23,595  

Vested

    (971,130 )   (15,696 )

Forfeited

    (201,539 )   (4,619 )
           

Unvested—December 31, 2009

    137,932   $ 3,280  

Vested

         

Forfeited

         
           

Unvested—December 31, 2010

    137,932   $ 3,280  

Vested

         

Forfeited

    (68,966 )   (1,640 )
           

Unvested—December 31, 2011

    68,966   $ 1,640  

Vested

         

Cancelled

    (68,966 )   (1,640 )
           

Unvested—March 31, 2012

         
           
           

        The purchase price for Barr Energy, LLC (acquisition date July 2007) included contingent consideration of 206,897 subordinated units of HSE with a grant date fair value of $23.78 per unit or $4.9 million. As of July 31, 2009, one third, or 68,965 of the contingent subordinated units valued at $1.6 million related to the acquisition of Barr Energy, LLC had vested and their fair value was recognized as additional goodwill.

        As of December 31, 2011 and 2010 the remaining contingent subordinated units outstanding are for the Barr Energy, LLC acquisition. In March 2012 in exchange for a payment of $5,000 by the Partnership, the remaining unvested contingent subunits were cancelled.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 12—Goodwill and Intangible Assets (Continued)

Intangible Assets

        Intangible assets subject to amortization and the changes in the carrying value are as follows (in thousands):

 
  Gross
Carrying
Amount
As of
December 31,
2011
   
   
   
   
   
   
 
 
   
   
   
   
  March 31, 2012  
 
  Additions   Impairments   Other   Held for
Sale
  Gross
Carrying
Amount
  Accumulated
Amortization
 

Customer relationships

  $ 57,688   $   $   $   $   $ 57,688   $ 31,855  

Customer contracts

    10,125                     10,125     8,622  

Non-compete agreements

    6,727                     6,727     6,512  

Other intangible assets(1)

    702                     702     450  
                                 

  $ 75,242   $   $   $   $   $ 75,242        

Accumulated amortization

    (45,436 )   (2,003 )               (47,439 )      
                                         

  $ 29,806                           $ 27,803        
                                         
                                         

 

 
  Gross
Carrying
Amount
As of
December 31,
2010
   
   
   
   
   
   
 
 
   
   
   
   
  December 31, 2011  
 
  Additions   Impairments   Other   Held for
Sale(1)
  Gross
Carrying
Amount
  Accumulated
Amortization
 

Customer relationships

  $ 40,535   $ 20,000   $   $   $ (2,847 ) $ 57,688   $ 30,071  

Customer contracts

    10,125                     10,125     8,446  

Non-compete agreements

    7,032     250             (555 )   6,727     6,483  

Other intangible assets

    808                 (106 )   702     436  
                                 

  $ 58,500   $ 20,250   $   $   $ (3,508 ) $ 75,242        

Accumulated amortization

    (39,850 )   (7,835 )           2,249     (45,436 )      
                                         

  $ 18,650                           $ 29,806        
                                         
                                         

(1)
"Held for sale" at December 31, 2011 represents intangibles owned by Terminaling.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 12—Goodwill and Intangible Assets (Continued)

 
  Gross
Carrying
Amount
As of
December 31,
2009
   
   
   
   
   
   
 
 
   
   
   
   
  December 31, 2010  
 
  Additions   Impairments   Other(1)   Held for
Sale(2)
  Gross
Carrying
Amount
  Accumulated
Amortization
 

Customer relationships

  $ 41,069   $   $ (534 ) $   $   $ 40,535   $ 25,126  

Customer contracts

    10,575     128     (9 )   (450 )   (119 )   10,125     7,654  

Non-compete agreements

    7,171         (139 )           7,032     6,630  

Other intangible assets(1)

    759     12,969     (1,095 )       (11,825 )   808     440  
                                 

  $ 59,574   $ 13,097   $ (1,777 ) $ (450 ) $ (11,944 ) $ 58,500        

Accumulated amortization

    (32,203 )   (8,490 )       294     549     (39,850 )      
                                         

  $ 27,371                           $ 18,650        
                                         
                                         

(1)
"Other" at December 31, 2010 is a disposal of Ethanol's sales contracts in connection with the Ethanol asset sale.

(2)
"Held for sale" at December 31, 2010 represents intangibles owned by Monroe.

        The Partnership tests its finite lived intangible assets when circumstances or events occur that indicate a potential impairment, see Note 2—Significant Accounting Policies.

        In November 2010, certain long-lived assets and intangible assets of Monroe were remeasured to fair value in conjunction with the Partnership's impairment evaluation for long-lived assets associated with the expected sale of Monroe. As a result of the Partnership's decision to sell Monroe, and indications of fair value less costs to sell from prospective buyers, the Partnership recognized an impairment charge on Monroe's intangibles of $1.1 million, representing a portion of the unamortized balance of Monroe's customer contracts and other intangible assets. This is recorded in Discontinued operationsLoss on discontinued operations, net in the Consolidated Statement of Operations in 2010.

        Due to the reasons discussed above under Goodwill, operating profits and cash flows for Terminaling and NCC were much lower than expected during 2010 and 2009, respectively, resulting in reduced earnings and cash flow forecasts. Effective August 2010, the Partnership recognized an impairment charge of $0.7 million, representing a portion of the unamortized balance of Terminaling's customer contracts, non-compete agreements and other intangible assets. Effective August 2009, the Partnership recognized an impairment charge of $5.3 million, representing the entire unamortized balance of NCC's customer relationships, customer contracts, non-compete agreements and other intangible assets.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 12—Goodwill and Intangible Assets (Continued)

        The remaining intangible assets are expected to be amortized as follows (in thousands):

 
  Years Ending December 31  
 
  Customer
Relationships
  Customer
Contracts
  Non-
Compete
Agreements
  Other
Intangibles
  Total  

2012

  $ 4,035   $ 400   $ 64   $ 35   $ 4,534  

2013

    2,856     577     63     25     3,521  

2014

    2,856     526     62     17     3,461  

2015

    1,478         26     14     1,518  

2016

    1,176             14     1,190  

Thereafter

    13,432             147     13,579  
                       

  $ 25,833   $ 1,503   $ 215   $ 252   $ 27,803  
                       
                       

(1)
Other intangibles consist primarily of patent costs associated with Anticline.

        Amortization expense for the years ended December 31, 2011, 2010 and 2009 was $7.8 million, $8.5 million and $9.4 million, respectively. As of December 31, 2011, the remaining amortization periods range from four to 25 years. The weighted average remaining amortization period is approximately fourteen years. Amortization expense for the three months ended March 31, 2012 and 2011 was $2.0 million and $1.9 million, respectively.

Note 13—Investments in Unconsolidated Affiliate

Monroe Gas Storage Company, LLC

        During the period January 1, 2009 through March 1, 2010 and prior, the Partnership applied the equity method of accounting to its interests in Monroe. As discussed further in Note 4—Business Combinations—Monroe Gas Storage Company, LLC, the Partnership gained control of Monroe effective March 1, 2010 and as of that date the Partnership discontinued the equity method of accounting for Monroe and the Partnership began reporting Monroe on a consolidated basis. As of January 1, 2010 the Partnership owned a 70% interest in Monroe and the carrying value of the Partnership's equity investment in Monroe was $40.8 million.

        As of December 31, 2010 and December 31, 2009, the Partnership owned a 70% interest in Monroe. During 2009, pursuant to several agreements, the Partnership attained additional membership interests in Monroe increasing its interest from 50% to 70% of Monroe's Class A membership interests.

        The Partnership sold all of its membership interest in Monroe in May 2011, as discussed further in Note 5—Discontinued Operations, Dispositions and Held for Sale.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 14—Asset Retirement Obligations

        The Partnership's asset retirement obligations are related to the wastewater disposal assets, crude oil lease automatic custody units, and prior to the sale of Monroe, its natural gas storage business, which have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned.

        The following is a reconciliation of the changes in the Partnership's asset retirement obligations from January 1, 2010 through March 31, 2012 (in thousands):

 
  Year Ended
December 31,
   
 
 
  Three Months
Ended
March 31, 2012
 
 
  2011   2010  

Beginning asset retirement obligation

  $ 1,166   $ 2,244   $ 1,552  

Business combination(1)

    176     1,524      

Liabilities incurred

    1,234     171     259  

Liabilities disposed and paid(2)

    (1,114 )   (1,233 )   (424 )

Accretion expense

    90     204     19  

Held for sale(1)

        (1,744 )    
               

Ending asset retirement obligation

  $ 1,552   $ 1,166   $ 1,406  
               
               

(1)
"Business combination" and "Held for sale" at December 31, 2010 represents asset retirement obligations of Monroe.

(2)
"Liabilities disposed and paid" represent asset retirement obligations of NCC which were retained and paid in 2011, and disposed of in the sale of NCC in 2010, respectively.

        Because remediation activities are still in process at NCC, $0.4 million of the $1.4 million total asset retirement obligation related to NCC properties at March 31, 2012, is reported within Accrued liabilities and other, and $1.0 million is reported within Other long-term liabilities. At December 31, 2011, $0.5 million of the $1.6 million total asset retirement obligation related to NCC properties is reported within Accrued liabilities and other, and $1.1 million is reported within Other long-term liabilities. The entire obligation at December 31, 2010 is reported within Other long-term liabilities. At December 31, 2011 and 2010, there were no assets legally restricted for the purpose of settling asset retirement obligations. The asset retirement obligation is reported as part of Other long-term liabilities in the accompanying Consolidated Balance Sheets.

        As of December 31, 2011 and 2010, $0.5 million in cash of one of the Partnership's water disposal subsidiaries was segregated into a highly liquid, short-term investment account to be used to fund that subsidiary's estimated asset retirement obligations. These amounts are reported in Other long-term assets in the accompanying Consolidated Balance Sheets.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 15—Debt

        Debt consists of the following (in thousands):

 
  December 31,    
 
 
  March 31, 2012  
Credit Facilities
  2011   2010  

High Sierra Energy Credit Facility, 3.50% interest, due March 16, 2014. 

  $   $   $  

High Sierra Energy, LP Revolver Facility, 4.29% interest, paid in full March 2011. 

   
   
35,000
   
 

Centennial Energy, LLC, Centennial Gas Liquids, ULC, High Sierra Crude Oil and Marketing, LLC and Asgard Energy, LLC as Co-Borrowers Revolver facility, 5.50% interest, paid in full March 2011. 

   
   
8,029
   
 

Monroe Gas Storage Company, LLC Construction and Term Loan Facility, non-recourse to the Partnership, 5.54% interest, paid in full May 2011. 

   
   
95,550
   
 

Petro Source Products, LLC (the former VIE) Revolver Facility, 9.0% interest, paid in full March 2011. 

   
   
8,374
   
 
               

Total Borrowings under lines of credit

          146,953      

Borrowings included in Liabilities of operations held for sale

        (95,550 )    
               

          51,403      

Current liabilities—Borrowings under lines of credit

        (23,090 )    
               

Total all Credit Facilities

  $   $ 28,313   $  
               
               

Term loan with variable interest of 4.30% at December 31, 2011. In addition to interest, quarterly payments of principal of $1.2 million are required through March 2013, thereafter $0.8 million through March 2014, at which time the remaining principal of $42.1 million plus accrued interest will become due in full. The loan is collateralized by substantially all of the assets of the Partnership and its subsidiaries. The loan was retired on June 19, 2012. 

 
$

51,535
 
$

 
$

49,472
 

Term loan with variable interest of 4.30% at December 31, 2011. In addition to interest, quarterly payments of principal of $1.5 million are required through March 2013, thereafter $1.0 million through March 2014, at which time the remaining principal of $51.8 million plus accrued interest will become due in full. The loan is collateralized by substantially all of the assets of the Partnership and its subsidiaries. The loan was retired on June 19, 2012. 

   
63,428
   
   
62,771
 

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 15—Debt (Continued)

 
  December 31,    
 
 
  March 31, 2012  
Credit Facilities
  2011   2010  

Note payable with interest fixed at 3.76%. The note is related to an insurance policy, requires 9 monthly payments of principal and interest of $65,118, and matures February 2012. The notes were retired on June 19, 2012. 

    128          

Capital lease obligation with interest fixed at 5.75%. The obligation is for a lease of water processing filtration equipment, requires monthly payments of principal and interest of $26,790, and matures December 2012. 

   
312
   
   
211
 

Note payable with interest fixed at 7.33%. The note required monthly payments of principal and interest of $8,871, had an original maturity of November 2013 and was collateralized by certain High Sierra Sertco, LLC compressor equipment.(1)

   
   
279
   
 

Note payable with interest fixed at 5.83%. The note required monthly payments of principal and interest of $10,038, had an original maturity of February 2014 and was collateralized by certain High Sierra Sertco, LLC compressor equipment.(1)

   
   
356
   
 

Note payable with interest fixed at 2.92%. The note is related to an insurance policy, required monthly payments of principal and interest of $68,872. Paid in full April 2011. 

   
   
204
   
 

Note payable with interest fixed at 5.96%. The note required monthly payments of principal and interest of $11,716, had an original maturity of January 2014 and was collateralized by certain High Sierra Sertco, LLC compressor equipment.(1)

   
   
395
   
 
               

    115,403     1,234     112,454  

Less current portion of debt

    (11,315 )   (525 )   (11,085 )
               

Long-term debt, net of current portion

  $ 104,088   $ 709   $ 101,369  
               
               

(1)
These notes were paid in full in February 2011.

High Sierra Credit Facility

        On March 16, 2011 the Partnership and certain of its wholly-owned subsidiaries ("the Borrowers") collectively entered into a credit facility agreement (the "Credit Facility") with a syndicate of participating lenders (collectively "the Lenders"). The Credit Facility provides for maximum borrowings of up to $215.0 million in the form of term loans, working capital loans, revolving credit facility loans

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 15—Debt (Continued)

or letters of credit, subject to the available borrowing base as defined. The Credit Facility is secured by substantially all assets of the borrowers and requires compliance with certain financial and restrictive covenants. Interest on borrowings under the Credit Facility is charged at the Bank Base Rate plus a margin, or the Eurodollar rate plus a margin that is based upon the Leverage Ratio of the Partnership, as defined, and as selected by the Partnership (the "Base Borrowing Rate").

        Interest on amounts borrowed under the Credit Facility term loans is at the Base Borrowing Rate plus a margin ranging from 4.0% to 4.5%, and is repayable in an amount equal to 1.875% of the initial aggregate principal amount, any accrued but unpaid interest due thereon, and any fees in respect thereof on the last day of each Fiscal Quarter, commencing with the fiscal quarter ending on June 30, 2011. Interest on amounts borrowed under the working capital facility is at the Base Borrowing Rate plus a margin ranging from 2.5% to 4.0%. Interest on amounts borrowed under the revolving credit facility is at the Base Borrowing Rate plus a margin ranging from 3% to 4.5%.

        Letter of credit fees range from 3.25% to 4% depending upon the Leverage Ratio of the Partnership, and whether the letters of credit are working capital letters of credit or for other purposes. Unutilized credit fees range from .625% to 0.75% on the unutilized portions of the working capital and revolving credit facilities. Amounts borrowed under the working capital and revolving credit facilities are due and payable no later than March 16, 2014, the termination date of the Credit Facility. The proceeds of the Credit Facility were partially utilized to pay off the HSE Credit Facility, the Marketing Credit Facility and the PS Products Facility. All three of these facilities were terminated, and no further borrowings or letters of credit are available under these facilities.

        At March 31, 2012 there were $43.7 million of letters of credit outstanding under the Credit Facility. At December 31, 2011, there were $56.6 million of letters of credit outstanding under the Credit Facility.

        In May 2011, the Partnership amended the Credit Facility ("Amendment No. 1"). Among other changes, the Partnership obtained consent from the Lenders to acquire Marcum, and an additional $80 million term loan commitment (the "Marcum Term Loan") under the Credit Facility (thereby increasing the maximum Credit Facility borrowings to $295 million). Further, the Credit Facility term loan repayment schedule was amended to require repayment of the Marcum Term Loan in an amount equal to 1.875% of the initial aggregate principal amount, any accrued but unpaid interest due thereon and any fees in respect thereof on the last day of each Fiscal Quarter, commencing with the fiscal quarter ending on June 30, 2011. In addition, High Sierra Water Services, LLC, a wholly-owned subsidiary formed to own and operate the acquired Marcum business, was added as a co-borrower to the Credit Facility.

        Total letter of credit fees expensed under all facilities and reported in Interest expense in the accompanying Consolidated Statements of Operations were $2.7 million, $2.9 million and $1.1 million for the years ended December 31, 2011, 2010 and 2009, respectively. Total letter of credit fees expensed under all facilities and reported in Interest Expense in the accompanying consolidated statements of operations were $0.5 million and $0.8 million for the three months ended March 31, 2012 and 2011, respectively.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 15—Debt (Continued)

        The High Sierra Credit Facility was retired on June 19, 2012 upon completion of the merger with NGL Energy Partners LP, as described in Note 23—Subsequent Events.

High Sierra Energy, LP Credit Facility

        On June 1, 2007, HSE entered into a Revolving Credit Agreement (the "HSE Credit Facility" or the "Facility") with a lending institution. The borrowers included HSE and certain of its subsidiaries. The HSE Credit Facility was amended and extended several times, with the most recent amendment, the Tenth Amendment, dated December 15, 2010. The amended HSE Credit Facility provided for maximum borrowings of up to $45 million, and permitted letters of credit of up to $10 million under the HSE Credit Facility. Interest on amounts borrowed under this credit facility ranged from 2.0% to 3.0% over Prime or 3.5% to 4.5% over LIBOR depending up the Consolidated Leverage Ratio of the Partnership, as defined. As of December 31, 2010 the Partnership had outstanding letters of credit under the HSE Credit Facility of $4.0 million.

        In March 2011, in connection with the Credit Facility, the HSE Credit Facility was paid in full.

High Sierra Energy Marketing Companies Credit Facility

        In June 2005, Centennial, its wholly-owned Canadian subsidiary CGL, HSCOM and Asgard (collectively "the Co-Borrowers") together with HS Marketing as guarantor, entered into a Credit Agreement (the "Marketing Credit Facility") with a lending institution. The Marketing Credit Facility permitted borrowings in the form of term loans, overdrafts, letters of credit or revolving loans for the purposes of (i) financing working capital requirements related to crude oil, natural gas, NGL's, asphalt and petroleum products, (ii) funding payments due Fortis under any swap contracts as defined, or (iii) providing letters of credit. The Marketing Credit Facility was amended several times, with the most recent amendment dated December 15, 2010.

        The amended Marketing Credit Facility permitted maximum borrowings of up to $30.0 million, available either as letters of credit or cash borrowings. Interest on borrowings, except for outstanding letters of credit, ranged from: (i) the greater of the Federal Funds Rate plus 0.50% per annum or the lender's prime rate plus 2.25% per annum (the "Base Rate"), or (ii) the Fortis Offered Rate ("FOR Rate") plus 3.75% per annum. As of December 31, 2010 the Co-Borrowers had letters of credit of $14.8 million outstanding under the Marketing Credit Facility at 5.5% interest.

Monroe Credit and Term Loan Facility—Non-Recourse to the Partnership

        In June 2008, Monroe closed on a Credit and Term Loan Facility ("Monroe Credit Facility") with a bank and a syndicate of lenders which provided for a construction loan, converting to a term loan upon "substantial completion", as defined, and certain other conditions. In connection with the Monroe Credit Facility, Monroe entered into a Pad Gas Lease Agreement (the "Original Pad Gas Lease"), as further discussed in Note 20—Commitments and Contingencies—Pad Gas Lease Agreements.

        The Monroe Credit Facility, as amended, provided for a construction loan commitment not to exceed $105 million. Interest on the construction loan and upon conversion, the term loan, was based

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 15—Debt (Continued)

upon the Company's maximum total debt to EBITDA ratio to a range of: (i) Fortis' prime rate plus a margin of 2.25% up to 4.25%, or (ii) LIBOR plus a margin of 3.25% up to 5.25%, at management's option. The repayment schedule, as amended, required quarterly payments of 1.5% of the principal amount outstanding under the Monroe Credit Facility commencing September 30, 2010, and at each quarter end thereafter. In addition the Monroe Credit Facility required that the Monroe maintain a debt service reserve and restricted contingent cash accounts. The terms of the amended Monroe Credit Facility also required maintenance of certain financial and other customary borrower covenants. Amounts and obligations associated with the Monroe Credit Facility were secured solely by the assets of Monroe.

        In connection with the sale of Monroe in May 2011, all amounts then due under the Monroe Credit Facility, were paid in full.

Monroe Interest Rate Swap Transactions

        In November 2008, Monroe entered into an interest rate swap agreement for a five-year period as an economic hedge of the risk associated with the variable rate interest payments under Monroe's Credit Facility. The notional principal amount of the swap contract at inception was $45 million. Pursuant to the swap agreement, Monroe paid 3.13% fixed interest and received LIBOR based variable interest from the swap counterparty ("swap 1 interest"). The difference between the fixed and LIBOR based "swap 1" interest amounts was received or paid every three months in arrears commencing September 1, 2009.

        In December 2008, Monroe entered into a second interest rate swap agreement for a five-year period as an economic hedge of the risk associated with the variable rate interest payments under Monroe's Credit Facility. The notional principal amount of the swap contract at inception was $15 million. Pursuant to the swap agreement, Monroe paid 2.74% fixed interest and received LIBOR based variable interest from the swap counterparty ("swap 2 interest"). The difference between the fixed and LIBOR based "swap 2" interest amounts was received or paid every three months in arrears commencing September 1, 2009.

        In connection with the sale of Monroe and the repayment in full of the Monroe Credit and Term Loan Facility in May 2011, the interest rate swap agreements were terminated.

Petro Source Products Credit Facility

        In August 2009, PS Products entered into a credit agreement with a bank (the "PS Products Facility"). The PS Products Facility as amended provided for cash borrowings or letters of credit up to a maximum amount of $55.0 million. PS Products paid an annual administrative fee of 2% of the maximum credit facility. Interest was payable monthly at an annual rate of 9%. The PS Products Facility was secured solely by substantially all assets of PS Products, guaranteed by certain PS Products members, and required compliance with certain financial covenants. At December 31, 2010 there were $34.4 million of letters of credit outstanding under the PS Products Facility.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 15—Debt (Continued)

        Interest incurred under the PS Products Facility was $.05 million, $0.1 million and $0.2 million for the years ended December 31, 2011, 2010 and 2009, respectively. Letter of credit fees expensed during the years ended December 31, 2011, 2010 and 2009 were $0.7 million, $2.0 million and $0.4 million, respectively, and are reported in Interest expense in the accompanying Consolidated Statements of Operations.

        In March 2011 in connection with HSE's Credit Facility and HSCOM's acquisition of PS Products, HSE provided a replacement letter of credit to the lender under the PS Products Facility for the existing letters of credit outstanding under the PS Products Facility at the acquisition date.

Extinguishment of Debt

        In connection with a sale leaseback of its railcar fleet as discussed in Note 20—Commitments and Contingencies—Sale Leaseback Transaction, the Partnership used $3.6 million of the sale proceeds to extinguish three notes payable. In connection with the extinguishment of debt the Partnership paid $0.2 million of prepayment fees, which are reported in Other income, net in the Consolidated Statements of Operations for the year ended December 31, 2010.

Aggregate Maturities

        The aggregate maturities of long-term obligations are as follows (in thousands):

Years ending December 31,
  As of
March 31, 2012
 

2012

  $ 8,366  

2013

    9,188  

2014

    94,900  
       

  $ 112,454  
       
       

Note 16—Equity Compensation Plan

        The Partnership has an Equity Incentive Plan (the "Plan"), which provides for two separate equity programs, (i) the Unit Issuance Program and (ii) the Option Grant Program. The Unit Issuance Program provides for awards of the Partnership's common units, subordinated units, restricted units or phantom units, either through immediate purchase or as a bonus for services. The Option Grant Program provides for the award of options to purchase limited partnership units of the Partnership, including common units, subordinated units, restricted units or phantom units. The term of an option may not exceed ten years from the date of grant. The Plan was amended in December 2011 to permit the award of restricted units and to clarify that equity awards would not have the same rights as common units to the extent provided in the award.

        The Partnership Agreement was amended in May 2011 to clarify that unvested equity awards are not allocated profits and losses and in December 2011 to clarify that equity awards may be made in exchange for services.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 16—Equity Compensation Plan (Continued)

        Administration of the Plan has been delegated by the Board of Directors to the Compensation Committee ("Committee"). The Committee may make awards to employees, non-employee members of the Board or non-employee consultants and other independent advisors. The Committee has authority to determine the number of units or options awarded, the vesting conditions, the purchase or exercise prices for units or options awarded, respectively, the term and any other features of the awards.

        The maximum number of units that may be issued over the term of the Plan is limited to no more than ten percent of the Partnership's outstanding units on a fully diluted basis, not including the units issuable under the Plan. Unvested units and options issued that subsequently fail to vest and are forfeited or cancelled are available for subsequent reissue under the Plan. As of December 31, 2011, 2010 and 2009 the number of outstanding subunits, restricted units and unexercised options awarded under the Plan was 167,608, 247,074 and 217,457, respectively. The Plan terminates upon the earlier of (i) ten years from adoption of the Plan, (ii) the date that all available units have been issued, or (iii) in connection with a merger, consolidation resulting in more than a 50% ownership change or a sale, transfer or disposition of substantially all of the Partnership's assets or units.

        Under the Unit Issuance Program, holders of common unit awards are entitled to full limited partner rights, including voting rights and the right to distributions. Holders of unvested subordinated units and phantom units awarded under the Unit Issuance Program, and option holders under the Option Issuance Program do not have any such rights until the awards have vested.

Option Grants

        In March 2006, options to purchase 5,000 common units were granted, which vest in equal annual 25% increments from the grant date, and expire six years from January 1, 2006, the effective date of grant. Of these, 1,250 were exercised and another 1,250 were forfeited during 2007. During the years ended December 31, 2007 through 2010, an additional 625 options vested in each year, and there were no exercises or forfeitures. As a result there are no unvested option grants under the Plan as of December 31, 2011. There have been no other option grants made by the Partnership. The Partnership computed the total fair value for these options using the Black Scholes option pricing model and the following weighted average assumptions:

Approximate risk free rate

    4.20 %

Expected dividend yield

    8.50 %

Expected volatility

    29 %

Expected weighted average life

    5 years  

Exercise price

  $ 21.18  

        Compensation expense for options was recognized on a straight-line basis over the related service period, adjusted for estimated pre-vesting forfeitures.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 16—Equity Compensation Plan (Continued)

Unit grants

        Subordinated, restricted and phantom units granted (collectively "Grant Units") convert to common units upon vesting. The units granted vest based upon employee service, and in some cases, based upon both employee service and achievement of performance targets, including targeted gross margin generated by the employee or a targeted distribution per limited partner unit.

        Compensation expense related to Grant Units with only service-based vesting is recognized on a straight-line basis over the applicable vesting period. Compensation expense for Grant Units with both service and performance based vesting is recognized beginning in the period management concludes it probable that the performance condition will be achieved, net of an estimate of pre-vesting forfeitures due to termination of employment prior to vesting.

        The following table summarizes employee equity compensation activity by type of equity instrument for the years ended December 31, 2011, 2010 and 2009 and for the three months ended March 31, 2012.

 
  Options   Subordinated and
Restricted
  All Units  
 
  Units   Fair Value   Units   Fair Value   Units   Fair Value  

Unvested—January 1, 2009

    1,250   $ 21.18     115,742   $ 18.08     116,992   $ 18.11  

Granted

              33,000     17.05     33,000     17.05  

Vested

    (625 )   21.18     (55,717 )   18.98     (56,342 )   19.00  

Forfeited

              (16,000 )   21.07     (16,000 )   21.07  
                                 

Unvested—December 31, 2009

    625   $ 21.18     77,025   $ 17.30     77,650   $ 17.33  

Granted

   
         
55,500
   
12.98
   
55,500
   
12.98
 

Vested

    (625 )   21.18     (25,883 )   17.45     (26,508 )   17.53  

Forfeited

                             
                                 

Unvested—December 31, 2010

      $     106,642   $ 15.04     106,642   $ 15.01  

Granted

   
         
42,500
   
18.90
   
42,500
   
18.90
 

Vested

              (43,833 )   14.70     (43,833 )   14.70  

Forfeited

              (9,167 )   13.63     (9,167 )   13.63  
                                 

Unvested—December 31, 2011

            96,142   $ 15.52     96,142   $ 15.52  

Granted

   
   
   
650,000
   
18.61
   
650,000
   
18.61
 

Vested

            (30,167 )   15.37     (30,167 )   15.37  

Forfeited

                         
                                 

Unvested—March 31, 2012

      $     715,975   $ 18.53     715,975   $ 18.53  
                                 
                                 

Exercisable—March 31, 2012

    2,500   $ 21.18                 2,500   $ 21.18  
                                   
                                   

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 16—Equity Compensation Plan (Continued)

        Total unit-based compensation recorded during the years ended December 31, 2011, 2010 and 2009 related to subordinated units, restricted units and options totaled $0.7 million, $0.7 million and $1.0 million, respectively. Total unit-based compensation recorded during the three months ended March 31, 2012 and 2011 related to subordinated units, restricted units and options totaled $0.2 million and $0.1 million, respectively. Compensation expense to be recognized in future periods related to the vesting of unvested subordinated and restricted units will be approximately $11.7 million over a weighted average period of 2.7 years, provided all performance and service conditions of the awards are met. As of March 31, 2012, there were 719,844 units available for grant under the Plan. In addition to the grants in the table above, the Partnership paid $5,000 in exchange for 68,966 unvested contingent subordinated units with a fair value per unit of $23.78 related to a business combination, which were then cancelled (see Note 12—Goodwill and Intangible Assets).

        On June 19, 2012, in connection with the merger with NGL Energy Partners, 645,833 of the subordinated and restricted units vested and 70,142 of the subordinated and restricted units were forfeited.

Note 17—Equity

High Sierra Energy GP, LLC Members' Equity

        The ownership interests in the Company consist of membership interests, with each membership interest evidencing a specific interest in the Company during its existence and in its assets upon dissolution. Generally, distributions paid by the Company are paid to the members on a pro rata basis in accordance with the membership interests held by each member.

High Sierra Energy, LP Partners' Capital

        Partners' capital at March 31, 2012 consists of 14,684,863 common units outstanding, representing a 98% effective aggregate ownership interest in the Partnership and its subsidiaries after giving effect to the 2% general partner interest.

General Partner

        The Company retains a two percent ownership interest in the Partnership. In addition to managing all of the operations of the Partnership, the Company has the authority to, among other things, distribute the Partnership's cash, and to acquire, dispose or mortgage any or all of the Partnership's assets. The Partnership reimburses the Company on a monthly basis for all direct and indirect expenses the Company incurs on its behalf, including rent. For the years ended December 31, 2011, 2010 and 2009, and for the three months ended March 31, 2012 and 2011, amounts incurred by the Company on behalf of the Partnership were not significant.

Incentive Distribution Rights

        Incentive Distribution Rights ("IDR's") are non-voting Limited Partner Interests issued to the Company that entitle the Company to receive incentive distributions if the amount distributed with

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 17—Equity (Continued)

respect to any quarter exceeds levels specified in the partnership agreement. Under the quarterly incentive distribution provisions, the Company is entitled, without duplication, to 15% of amounts distributed in excess of $0.45 per unit, referred to as the minimum quarterly distribution ("MQD"), 25% of amounts distributed in excess of $0.5625 per unit, and 50% of amounts distributed in excess of $0.675 per unit.

Partnership Distributions

        The Partnership may elect to distribute 100% of its available cash within 45 days after the end of each quarter to unit holders of record and to its general partner. Available cash is generally defined as all cash and cash equivalents on hand at the end of each quarter, less reserves established by the Company for future requirements.

        Per unit cash distributions on outstanding units and the portion of the distributions representing an excess over the MQD were as follows:

 
  Year Ended December 31,    
   
 
 
  Three Months Ended March 31, 2012  
 
  2011   2010   2009  
 
  Distribution(1)   Excess
Over MQD
  Distribution(1)   Excess
Over MQD
  Distribution(1)   Excess
Over MQD
  Distribution(1)   Excess
Over MQD
 

First Quarter

  $   $   $ 0.6300   $ 0.1800   $ 0.6100   $ 0.1600   $ 0.30   $  

Second Quarter

  $   $   $   $   $ 0.6100   $ 0.1600              

Third Quarter

  $ 0.1500   $   $   $   $ 0.6300   $ 0.1800              

Fourth Quarter

  $ 0.3000   $   $   $   $ 0.6300   $ 0.1800              

(1)
Distributions represent those declared in the applicable period.

        Total distributions made to common unitholders and the Company were as follows (in thousands):

 
  Distributions Paid  
Year
  Common
Unitholders
  General
Partner
Incentive
  General
Partner
2%
  Total  

2012

  $ 4,397   $   $ 90   $ 4,487  

2011

    6,589         134     6,723  

2010

    9,257     452     183     9,892  

2009

    33,407     1,537     682     35,626  

        No distributions were made or for any of the four quarters during the year ended December 31, 2010. The Partnership recommenced making cash distributions in August 2011. On May, 15, 2012, the Partnership paid a distribution of $0.30 per unit to unitholders of record on March 31, 2012 for the period January 1, 2012 through March 31, 2012. The total distribution paid was $4.5 million, including $4.4 million to common unit holders and $0.1 million paid to the Company for its general partner interest.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 17—Equity (Continued)

Common Unitholder Repurchase Right

        In May 2011 the Partnership sold 385,000 common limited partner units to two investors at $26.00 unit, receiving cash proceeds of approximately $10.0 million. The proceeds were used to partially fund the Marcum Acquisition.

        The holders of these units have the right to require the Partnership to repurchase these units plus any unpaid distributions during the 90 day period following the earlier of May 13, 2014 or a change in control. The repurchase price per unit is fixed at $32.75 per unit. In addition, the Partnership has the right to purchase 77,000 of these common limited partner units from the unitholders for a repurchase price per unit of $26.00 plus an amount equivalent to 8% per annum as of the call date, plus unpaid distributions. The Partnership's repurchase right is effective beginning on the issuance date until the earlier of a change in control, an initial public offering or a transfer of the common limited partner units to another investor.

Note 18—Significant Customers

        The Partnership had one customer that accounted for approximately 17%, 18% and 20% of consolidated revenues for the years ended December 31, 2011, 2010 and 2009, respectively, and for 20% and 14% of consolidated revenues for the three months ended March 31, 2012 and 2011, respectively. This same customer accounted for 14% and 22% of consolidated accounts receivable as of December 31, 2011 and 2010, respectively, and for 14% of consolidated accounts receivable as of March 31, 2012 and 2011. One other customer of the Partnership accounted for 12%, 3% and 6% of consolidated revenues for the years ended December 31, 2011, 2010 and 2009, respectively, and for 9% and 6% of consolidated revenues for the three months ended March 31, 2012 and 2011, respectively. This same customer accounted for 11% and 8% of consolidated accounts receivable as of December 31, 2011 and 2010, respectively, and for 1% and 6% of consolidated accounts receivable as of March 31, 2012 and 2011, respectively. No other customers who accounted for greater than 10% of consolidated revenues or accounts receivable.

Note 19—Related Parties

        The Partnership transacts business with several related party entities. These related parties are owned and or operated by officers and or employees of the Partnership. Types of transactions with related parties include purchasing and selling product, purchasing transportation service, leasing of office and yard space, purchasing administrative and clerical services, dismantling of facilities, advancing funds to and from, purchasing of equipment services, purchases of engineering feasibility consulting services, purchases of project management services, purchasing pipeline transportation, purchases

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 19—Related Parties (Continued)

environmental remediation services and loans from/ to. The following table summarizes the activity with these related parties (in thousands):

 
  Year Ended December 31,   Three Months
Ended
March 31,
2012
 
 
  2011   2010   2009  

Purchases of product, primarily crude oil

  $ 63,770   $ 35,124   $ 25,877   $ 20,077  

Sales of product, primarily crude oil

    4,438     4,331     3,981      

Purchases of transportation services

    657             370  

Rentals paid for office and facilities under lease agreements

    41     88     386     3  

Administrative and clerical service fees paid

    372     36     1,595     122  

Fees paid for equipment services

    121     10     28      

Engineering and feasibility consulting fees

    142     11     1,573     139  

Project management fees

    163     2         125  

Environmental remediation services costs paid

    602              

        As of December 31, 2011 and 2010 the Partnership had payables of $6.7 million and $1.0 million, respectively, to these related parties, and as of December 31, 2011 and 2010, the Partnership had receivables of $0.5 million and zero, respectively, from these related parties. As of March 31, 2012, the Partnership had payables of $7.9 million to these parties and receivables of $0.8 million from these parties.

Note 20—Commitments and Contingencies

Offset to Outstanding Derivative Contracts

        The Partnership maintains a minimum and measured exposure to commodity price risk through a combination of purchase and sale contracts and hedging policies. A large percentage of our business is hedged by contracting on a "back-to-back" basis where physical purchases are matched with physical sales. In those instances when the matching of physical transactions may be less than optimal, the Partnership utilizes financial hedges to lock-in margins. Although the Partnership seeks to maintain an aggregate position that is balanced within our supply and logistics activities, the Partnership purchases crude oil, condensate, and NGLs from hundreds of locations and may experience net unbalanced physical positions for short periods of time as result of production, transportation and delivery variances. All financial derivative positions have a direct physical offset.

Royalties

        In connection with the purchase of AntiCline, the Partnership agreed to pay a 5% royalty if the technology acquired was used outside of the current leased property. No royalties were incurred or

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 20—Commitments and Contingencies (Continued)

paid during the years ended December 31, 2011, 2010 or 2009 under this commitment. This provision terminated in March 2011 with the acquisition of the remaining membership interests in Anticline by the Partnership.

Operating Leases

        The Company leases land, office space, and equipment under leases with varying expiration dates through 2017. Rental expense for the years ended December 31, 2011, 2010 and 2009 was $21.4 million, $17.1 million and $14.7 million, respectively. Rental expense for the three months ended March 31, 2012 and 2011 was $6.1 million and $4.6 million, respectively. Future minimum rental commitments for the next five years and thereafter are as follows (in thousands):

Years Ending December 31,
  As of
March 31, 2012
 

2012

  $ 23,049  

2013

    27,157  

2014

    23,351  

2015

    17,062  

2016

    16,124  

Thereafter

    39,725  
       

  $ 146,468  
       
       

Sale Leaseback Transaction

        In June 2010 a wholly-owned subsidiary of the Partnership entered into a sale leaseback of its fleet of railcars. Proceeds from the sale were $8.1 million, which were utilized in part to retire three notes payable with aggregate outstanding principal and interest of $3.6 million. The railcars had a carrying value of $2.6 million. Of the total gain on sale of $5.6 million, the Partnership recognized $0.6 million as of the sale date within Other income (loss), net, and has amortized $0.5 million of the deferred gain as a reduction to rent expense during each of the years ended December 31, 2011 and 2010 within Operating expenses in the Consolidated Statements of Operations. The current and noncurrent portions of the remaining unamortized deferred gain of $0.9 million and $2.5 million, respectively, are reported in Accrued liabilities and other and Other long term liabilities in the Consolidated Balance Sheet at December 31, 2011.

        Under the lease agreement, the Partnership leased the railcars back from the purchaser for periods ranging from three to seven years. Required minimum lease payments totaling $3.8 million are included in the future minimum lease rental commitments information above. The obligations of the subsidiary under the lease are guaranteed by another of the Partnership's wholly-owned subsidiaries.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 20—Commitments and Contingencies (Continued)

Pad Gas Lease Agreements

        On June 13, 2008, Monroe entered into a Pad Gas Master Lease Agreement (the "Original Pad Gas Lease") with an affiliate of Fortis (the "Original Lessor"). Under the Original Pad Gas Lease, Monroe agreed to lease 3,500,000 MMBtu's of pipeline quality natural pad gas for injection into the project reservoir to provide reservoir pressures adequate to enable injection and withdrawal of natural gas from the reservoir. Delivery of pad gas did not occur and the Original Pad Gas Lease was terminated during June 2009. In connection with the termination of the Original Pad Gas Lease, Monroe paid $2.4 million to terminate the lease and novate certain related contractual commitments.

        Simultaneous with the termination of the Original Pad Gas Lease, Monroe entered into a New Pad Gas Lease Agreement. The New Pad Gas Lease required an initial upfront payment of $17.2 million at inception to secure delivery and to novate the prior contractual commitments associated with the prior lease. The fair value of $7.6 million assigned to the New Pad Gas Lease was reported in Current assets—Assets of operations held for sale in the Consolidated Balance Sheets as of December 31, 2010, along with other held for sale assets. Amortization expense recognized within Loss from discontinued operations, net was $3.1 million for the year ended December 31, 2010. During November 2010, the Partnership recognized an impairment charge of $0.7 million within Loss from discontinued operations, net, representing a portion of the unamortized balance of the New Pad Gas Lease.

        During May 2010, pursuant to an agreement related to the contractual gas delivery schedule, Monroe agreed to pay the lease counterparty $0.9 million as compensation for losses incurred as a result of Monroe's actual vs. scheduled acceptance of gas under the terms of the New Pad Gas Lease. On June 9, 2010, Monroe took delivery of the entire remaining pad gas in exchange for a cash payment of $1.2 million in full settlement of Monroe's obligation, which is reported within Loss from discontinued operations, net in the Consolidated Statements of Operations.

Legal Contingencies

        The Partnership is subject to a variety of risks and disputes, and is a party to various legal proceedings in the normal course of its business. The Partnership maintains insurance policies in amounts and with coverage and deductibles as it believes reasonable and prudent. While it is not possible to predict the outcome of the legal actions with certainty, management is of the opinion that appropriate provisions and accruals for potential losses associated with all legal actions have been made in the consolidated financial statements.

        In February 2012, the Partnership, several of its subsidiaries and other unaffiliated parties, were notified of a claim for wrongful death and failure to maintain adequate safety precautions. At this time, the Partnership is not able to determine what amount, if any, for which it might ultimately be held liable. In March 2012, a vehicle collided with a truck owned and operated by the Partnership, which resulted in a fatality. At this time, the Partnership is not able to determine whether it will be held liable for this incident. The Company believes that the amount of its liability for these incidents, if any, would be covered under existing insurance coverage.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 20—Commitments and Contingencies (Continued)

        During January 2012, the purchaser of Asgard ("Purchaser of Asgard") notified the Partnership of a claim of a breach in representation by the Partnership, because the Partnership did not disclose the existence of certain alleged swap and option transactions with a third party that occurred prior to the sale of Asgard to Purchaser of Asgard. The Partnership claims that it did not enter into these alleged transactions and is disputing the claims. Purchaser of Asgard is seeking indemnification from the sellers (the Partnership and its partner in Asgard) for losses it may sustain. The Partnership believes that the maximum amount being claimed is $2.7 million; however, in any event that the maximum liability of the sellers is $1.6 million under the purchase and sale agreement, and the Partnership's share of any loss is limited to 75% of the total loss. The Partnership believes the allegations made by the Purchaser of Asgard are without merit and intends to vigorously defend against the alleged claims.

        In November 2011, the purchaser of Monroe ("Purchaser of Monroe") notified the Partnership of a claim of breach of contract in connection with the Partnership's sale of Monroe, which closed on May 31, 2011. Purchaser of Monroe claimed that the gas storage reservoir that was sold in conjunction with the sale of Monroe contained over two and one half Bcf of natural gas less than what the Partnership had represented during the sales process; Purchaser of Monroe claimed that, as a result, it has sustained a financial loss, including excess operating and capital costs, of between $10 million and $20 million. The Partnership's share of total escrowed sales proceeds remained in escrow pending settlement. See Note 23—Subsequent Events, for additional information regarding this settlement.

        In September 2010, Pemex Exploracion y Produccion ("Pemex") filed a lawsuit against a number of defendants, including the Partnership. Pemex alleges that the Partnership and the other defendants purchased condensate from a source that had acquired the condensate illegally from Pemex. The Partnership does not believe that it had knowledge at the time of the purchases of the condensate that such condensate would later be alleged to have been sold illegally. The proceedings are in an early stage, and as a result, the Company cannot reliably predict the outcome of this litigation. The Partnership believes that it has good defenses and also believes that, in the event of an adverse outcome, its total exposure is not expected to be material to the Company. However, future adverse rulings by the court could result in material increases to the maximum potential exposure. The Partnership recorded an accrued liability during the three months ended March 31, 2012, based on its best estimate of the low end of the range of probable loss.

        In May 2010, two lawsuits were filed in Kansas and Oklahoma by numerous oil and gas producers (the "Associated Producers"), asserting that they were entitled to enforce lien rights on crude oil purchased by the Partnership. These cases were subsequently transferred to the United States Bankruptcy Court for the District of Delaware, where they are pending. These claims relate to the bankruptcy of SemCrude, L.P. The Associated Producers are claiming damages against all defendants in excess of $72 million and assert that the Partnership's allocated share of that is in excess of $2.1 million. The parties are in the discovery phase of the cases and no trial date has been set.

        During 2009, the Partnership filed lawsuits against the former owners of NCC that claim the prior owners operated NCC imprudently subsequent to the Partnership's acquisition of NCC, and violations of certain provisions of the purchase agreement. The defendants filed a motion for arbitration, which was denied and was appealed to the state Court of Civil Appeals. The motion for arbitration was

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 20—Commitments and Contingencies (Continued)

awarded by the Court of Civil Appeals and was upheld by the Oklahoma State Supreme Court. In June 2011 the Partnership and the prior owners of NCC (collectively the "parties") reached a settlement and mutually agreed to release each other from all claims. Among other things, the parties agreed to distribute unsettled escrow equally to each party in the amount of $0.5 million, and in addition the prior owners agreed to relinquish all rights, title and interest in 76,389 common LP units previously held as of the settlement date.

        In July 2009, HSCOM sold a bankruptcy claim it had against SemCrude LP to SilverPoint Capital Partners, LLC ("SPCP") for $3.5 million. Under the related sales agreement, if the claim was subsequently disallowed or impaired, in whole or in part, SPCP is entitled to sell the impaired portion back to HSCOM under certain conditions. Those conditions have occurred and HSCOM negotiated a settlement with SPCP in February 2012 in the amount of $2.2 million, including interest, HSCOM recorded the settlement within Other Income (expense)—Other income (loss), net in the accompanying Consolidated Statement of Operations for the year ended December 31, 2011. In a related matter, as a result of settlement of all remaining priority claims with SemGroup, HSCOM received a payment of $443,000 in March 2012.

        In early 2011, IC-CO, Inc. and W.E.O.C., Inc. filed an action in the United States District Court for the Eastern District of Oklahoma against J. Aron & Company. The claims asserted in the IC-Co action are identical to those asserted in the Samson and Associated Producers actions. IC-CO and W.E.O.C. sought recovery of sums they were owed for crude oil they had sold and not been paid for. The amount of their claims is relatively small, approximately $80,000. However, their Complaint also seeks Class Action Certification status on behalf of all other producers located in the State of Oklahoma. The Company believes it has meritorious defenses to the claims, including those which it has raised in the Associated Producers action and that the IC-CO claims are now barred by applicable statute of limitations.

        Centennial and HSCOM settled a claim alleging injection of nonconforming crude oil into a crude oil pipeline during 2009 with payment in the amount of $0.5 million which was reported within General and administrative expenses in the Consolidated Statements of Operations during 2009.

        During July 2008, there was a fatal accident at one of the Partnership's water facilities that resulted in the death of an employee while the employee was performing routine job responsibilities. The family of the employee filed a substantial certainty claim under Oklahoma law against the Partnership in July 2009. This claim was settled in February 2011. The amount of the claim that was not covered by the Partnership's insurance was $0.2 million, which was recognized as General and administrative expenses in the Consolidated Statement of Operations during 2010 and paid to the employee's family in March 2011.

        In July 2008, the Partnership executed an agreement to sell the majority of the methyl tertiary butyl ether ("MTBE") plant assets to a third party. During 2009, the Partnership received a final payment due of $0.4 million and title of the asset transferred to the purchaser. In connection with the dismantlement, relocation and rebuilding of the MTBE plant, the Partnership was involved in a dispute with a construction contractor. In March 2009, the contractor agreed to pay to the Partnership

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 20—Commitments and Contingencies (Continued)

$0.3 million, and the Partnership agreed to pay the contractor $0.2 million in full settlement of all claims.

        One of the Partnership's facilities is operating with all but one of the required permits. The Partnership has applied for the permit, which is necessary for ongoing operations. The Partnership has been informed by the State of Wyoming that it has fulfilled all of the obligations necessary to receive the permit; however, the Partnership believes that denial of the permit application could adversely affect operations. The Partnership has continued to communicate with the State of Wyoming about the status of the permit. The Partnership believes that the permit will be granted, but is unable to determine the timing of any action by the State of Wyoming.

Note 21—Employee Benefits

        In March 2007 the Partnership adopted the High Sierra Shared Services, LLC 401(k) & Profit Sharing Plan (the "Plan"). Employees of the Partnership and its subsidiaries over 18 years of age are eligible to participate in the Plan upon completion of 60 days of service. The Partnership may make discretionary matching contributions of 50% of the first 6% of participating employee compensation. The Partnership may also make additional discretionary profit sharing contributions. The Partnership elected to make discretionary matching contributions of 3% of an eligible employee's salary to all eligible employees' 401(k) plan accounts for the years ended December 31, 2011 and 2009 and the three months ended March 31, 2012. The Partnership did not elect to make a discretionary matching contribution for the year ended December 31, 2010.

        The Partnership made contributions of approximately $0.5 million, $0.9 million and $1.2 million during the years ended December 31, 2011, 2010 and 2009, respectively, and $0.3 million and $0.1 million during the three months ended March 31, 2012 and 2011, respectively. In addition, the Partnership made discretionary profit sharing contributions of $0.5 million for eligible participants to the Plan during the first quarter of 2012 and none during the first quarter of 2011.

        The Plan was amended effective January 1, 2012. Among other changes, the discretionary matching contribution was changed to 100% of the first 1% of participating employee eligible compensation and 50% of the next 5% of participating employee compensation.

Note 22—Income Taxes

        Current income tax expense of $0.4 million and $1.2 million are reported in Income tax expense (benefit) in the Consolidated Statements of Operations for the three months ended March 31, 2012 and 2011, respectively. Deferred income tax (benefit) of $(0.9) million is reported in Income tax expense (benefit) in the Consolidated Statements of Operations for the year ended December 31, 2011. Current and deferred income tax (benefit) of $(0.2) million and $(1.4) million, respectively, is reported in Income tax expense (benefit) in the Consolidated Statements of Operations for the year ended December 31, 2010. Current and deferred tax expense of $0.5 million and $1.6 million, respectively, is reported in Income tax expense (benefit) in the Consolidated Statement of Operations for the year ended December 31, 2009. Deferred tax (benefit) and expense for the years ended December 31, 2011,

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 22—Income Taxes (Continued)

2010 and 2009 resulted from a deferred tax liability and asset, respectively, for unrealized gains and losses recognized by CGL, the Partnership's Canadian subsidiary. The deferred tax asset amounts are reported in Prepaids and other assets, while the liability amounts are reported in Accrued liabilities and other in the Consolidated Balance Sheets at December 31, 2011 and 2010.

        The Partnership does not have any material unrecognized tax benefits associated with uncertain tax positions.

Note 23—Subsequent Events

        The Company evaluated subsequent events through September 4, 2012, the date the financial statements were issued.

Credit Facility Covenant Waiver

        In March 2012, the Partnership and the Credit Facility lenders determined that there was noncompliance with a restrictive covenant under the Credit Facility. The restrictive covenant requires perfection of security interests in collateral property, and the Partnership had not perfected a security interest on a property with a cost of approximately $4.6 million. On March 30, 2012 the Partnership was granted a waiver permitting the Partnership a period of ninety days to cure the covenant violation. The credit facility was retired on June 19, 2012.

Monroe Settlement

        As a result of continuing settlement negotiations, the Partnership and the Purchaser of Monroe reached an agreement in principle to settle the alleged claims made by the Purchaser of Monroe, as discussed above in Note 20—Commitments and Contingencies—Legal Contingencies. The Partnership's total settlement amount was $3.6 million (net of the working capital settlement described below), of which $1.9 million was recorded as a loss during the year ended December 31, 2011, and of which $1.7 million was recorded as a loss during the three months ended March 31, 2012.

        In addition to the above, the Partnership and the Purchaser of Monroe have also agreed in principle to finalize the working capital adjustment, discussed in Note 5—Discontinued Operations, Dispositions and Held for Sale—Monroe, whereby the Partnership is to receive approximately $0.3 million, representing the Partnership's portion of the working capital adjustment amount.

Sale of High Sierra Terminalling

        On May 31, 2012, the Partnership completed the sale of High Sierra Terminalling, LLC to an officer of the Company in exchange for $2.5 million in cash, subject to a working capital adjustment of $0.2 million. As a result of the sale, the Company recognized an impairment of the Terminalling assets held for sale as of March 31, 2012 in the amount of $5.4 million, which is reported within Loss from discontinued operations, net in the accompanying Consolidated Statement of Operations for the three months ended March 31, 2012.

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Notes to the Consolidated Financial Statements (Continued)

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 23—Subsequent Events (Continued)

Acquisition

        On May 22, 2012 the Partnership completed the purchase of a group of companies involved in the crude oil gathering, trucking, and waste water disposal businesses, in exchange for an aggregate cash payment of $23.4 million, subject to customary adjustments for working capital and certain capital expenditures.

Merger with NGL Energy Partners LP

        On June 19, 2012, the Company completed a merger with NGL Energy Holdings LLC whereby the Company became a wholly-owned subsidiary of NGL Energy Holdings LLC. The members of the Company received consideration of $50 million in cash and ownership interests in NGL Energy Holdings LLC. Concurrent with this merger, the Partnership completed a merger with NGL Energy Partners LP, whereby the Partnership became a wholly-owned subsidiary of NGL Energy Partners LP. The partners of the Partnership received consideration of $194.2 million in cash (inclusive of payments made by NGL Energy Partners LP to settle certain of High Sierra Energy, LP's long-term debt and other obligations) and 18,018,468 common units in NGL Energy Partners LP. Upon completion of the merger, the Partnership retired all of its term loans and notes payable.

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Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
SemGroup Corporation
Tulsa, Oklahoma

        We have audited the accompanying balance sheets of SemStream Non-Residential Division (the "Company") as of December 31, 2010 and 2009 (Subsequent to Emergence), and the related statements of operations, changes in net parent equity (deficit), and cash flows for the year ended December 31, 2010, and for the one month ended December 31, 2009 (Subsequent to Emergence), and for the eleven months ended November 30, 2009, and for the year ended December 31, 2008 (Prior to Emergence). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of SemStream Non-Residential Division at December 31, 2010 and 2009 (Subsequent to Emergence), and the results of its operations and its cash flows the year ended December 31, 2010 and for the one month ended December 31, 2009 (Subsequent to Emergence), and for the eleven months ended November 30, 2009 and for the year ended December 31, 2008 (Prior to Emergence), in conformity with accounting principles generally accepted in the United States of America.

        As discussed in Note 1 to the financial statements, effective November 30, 2009, the Company emerged from bankruptcy and applied fresh-start accounting. As a result, the statements of operations and cash flows for the year ended December 31, 2010 and for the one month ended December 31, 2009, are presented on a different basis than that for the periods before fresh-start and, therefore, are not comparable.

/s/ BDO USA, LLP

BDO USA, LLP
Dallas, Texas
November 3, 2011

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Table of Contents


SemStream Non-Residential Division

Balance Sheets

(Dollars in thousands)

 
  Subsequent to Emergence  
 
  December 31,
2010
  December 31,
2009
 

ASSETS

             

Current assets:

             

Accounts receivable

  $ 81,555   $ 43,300  

Inventories

    103,411     133,710  

Derivative assets

    4,367     2,560  

Margin deposits

    12,570     26,876  

Other current assets

    995     7,694  
           

Total current assets

    202,898     214,140  
           

Property, plant and equipment (net of accumulated depreciation of $2,342 at December 31, 2010 and $175 at December 31, 2009)

    48,028     42,812  

Goodwill

    50,071     50,071  

Other intangible assets (net of accumulated amortization of $3,077 at December 31, 2010 and $217 at December 31, 2009)

    13,923     16,783  

Other assets

    3,297     3,854  
           

Total assets

  $ 318,217   $ 327,660  
           
           

LIABILITIES AND NET PARENT EQUITY

             

Current liabilities:

             

Accounts payable

  $ 73,530   $ 44,708  

Advances from parent

        5,045  

Derivative liabilities

    13,418     25,804  

Payables to pre-petition creditors

    202     10,202  

Other current liabilities

    3,224     2,318  
           

Total current liabilities

    90,374     88,077  
           

Other noncurrent liabilities

    167     161  

Commitments and contingencies (Note 6)

             

Net parent equity

    227,676     239,422  
           

Total liabilities and net parent equity

  $ 318,217   $ 327,660  
           
           

   

The accompanying notes are an integral part of these financial statements.

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Table of Contents


SemStream Non-Residential Division

Statements of Operations

(Dollars in thousands)

 
  Subsequent to Emergence    
  Prior to Emergence  
 
  Year
Ended
December 31,
2010
  Month
Ended
December 31,
2009
   
  Eleven Months
Ended
November 30,
2009
  Year
Ended
December 31,
2008
 
 
   
 
 
   
 
 
   
 

Revenues, including revenues from affiliates (Note 9):

                             

Product sales

  $ 712,270   $ 63,261       $ 418,521   $ 1,505,020  

Other

    2,194     184         2,049     4,889  
                       

Total revenues

    714,464     63,445         420,570     1,509,909  

Expenses, including expenses from affiliates (Note 9):

                             

Costs of products sold, exclusive of depreciation and amortization shown below

    691,823     75,699         420,611     1,675,912  

Operating

    6,985     1,468         7,229     7,667  

General and administrative

    8,110     1,290         4,123     5,698  

Depreciation and amortization

    5,040     392         3,815     3,927  
                       

Total expenses

    711,958     78,849         435,778     1,693,204  
                       

Operating income (loss)

    2,506     (15,404 )       (15,208 )   (183,295 )

Other expenses (income):

                             

Interest expense

    3,703     761         2,154     1,711  

Other expense (income), net

    (2,983 )           (2 )   61  
                       

Total other expenses, net

    720     761         2,152     1,772  
                       

Income (loss) before reorganization items

    1,786     (16,165 )       (17,360 )   (185,067 )

Reorganization items gain (loss), including expenses allocated from affiliates (Note 9)

   
   
       
26,470
   
(25,247

)
                       

Net income (loss)

  $ 1,786   $ (16,165 )     $ 9,110   $ (210,314 )
                       
                       

   

The accompanying notes are an integral part of these financial statements.

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SemStream Non-Residential Division

Statements of Changes in Net Parent Equity (Deficit)

(Dollars in thousands)

Balance at December 31, 2007 (Prior to emergence)

  $ (36,249 )

Net loss

    (210,314 )

SemGroup interest capitalized to property, plant and equipment

    99  
       

Balance at December 31, 2008 (Prior to emergence)

    (246,464 )

Net loss, prior to implementation of Plan of Reorganization

    (89,823 )
       

Balance prior to implementation of Plan of Reorganization

    (336,287 )

Implementation of Plan of Reorganization

    590,075  
       

Balance at November 30, 2009 (Subsequent to emergence)

    253,788  

Net loss

    (16,165 )

Net contributions from SemGroup

    1,799  
       

Balance at December 31, 2009 (Subsequent to emergence)

    239,422  

Net income

    1,786  

Net distributions to SemGroup

    (13,532 )
       

Balance at December 31, 2010 (Subsequent to emergence)

  $ 227,676  
       
       

   

The accompanying notes are an integral part of these financial statements.

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Table of Contents


SemStream Non-Residential Division

Statements of Cash Flows

(Dollars in thousands)

 
  Subsequent to Emergence    
  Prior to Emergence  
 
  Year
Ended
December 31,
2010
  Month
Ended
December 31,
2009
   
  Eleven Months
Ended
November 30,
2009
  Year
Ended
December 31,
2008
 
 
   
 
 
   
 
 
   
 

Cash flows from operating activities:

                             

Net income (loss)

  $ 1,786   $ (16,165 )     $ 9,110   $ (210,314 )

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:

                             

Depreciation and amortization          

    5,040     392         3,815     3,927  

Loss (gain) on disposal of long-lived assets

    (34 )               61  

Provision for losses on accounts receivable

        617             40  

Gain on fresh start reporting                    

                (98,933 )    

Other non-cash reorganization items

                2,113      

Changes in assets and liabilities:          

                   
 
   
 
 

Decrease (increase) in accounts receivable

    (38,255 )   (3,587 )       22,115     75,263  

Decrease (increase) in inventory          

    29,129     3,321         (41,628 )   103,384  

Change in net derivative assets/liabilities                              

    (14,193 )   7,395         24,362     (49,713 )

Decrease (increase) in margin deposits

    14,306     (4,497 )       (14,779 )   43,917  

Decrease (increase) in other assets          

    7,256     4,332         (6,352 )   (3,637 )

Increase (decrease) in accounts payable

    28,072     2,529         38,137     (125,635 )

Decrease in payables to pre-petition creditors

    (10,000 )                

Increase (decrease) in other liabilities

    1,323     212         (5,317 )   1,197  
                       

Net cash provided by (used in) operating activities

    24,430     (5,451 )       (67,357 )   (161,510 )
                       

Cash flows from investing activities:

                             

Capital expenditures

    (6,129 )   (1,732 )       (2,806 )   (7,189 )

Proceeds from sale of long-lived assets

    687                 9  
                       

Net cash used in investing activities

    (5,442 )   (1,732 )       (2,806 )   (7,180 )
                       

Cash flows from financing activities:

                             

Change in book overdrafts

    (400 )   339         (220 )   238  

Principal payments on capital lease obligations

    (11 )           (11 )   (9 )

Net contributions from (distributions to) SemGroup

    (18,577 )   6,844         70,394     168,461  
                       

Net cash provided by (used in) financing activities

    (18,988 )   7,183         70,163     168,690  
                       

Net change in cash and cash equivalents

                     

Cash and cash equivalents at beginning of period

                     
                       

Cash and cash equivalents at end of period

  $   $       $   $  
                       
                       

   

The accompanying notes are an integral part of these financial statements.

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Table of Contents


SemStream Non-Residential Division

Notes to Financial Statements

1. OVERVIEW

Basis of presentation

        SemStream, L.P. is a wholly owned subsidiary of SemGroup Corporation engaged in the terminalling, storage, marketing and distribution of propane and other natural gas liquids in the United States. Its operations included sales to retail, wholesale and commercial customers linked to purchases from suppliers, and encompassed three primary focus areas: (i) wholesale marketing at both private and common carrier terminals; (ii) natural gas liquids supply to retail, petrochemical and commercial customers; and (iii) residential propane supply in Arizona.

        As described in Note 10, on November 1, 2011, SemStream, L.P. contributed certain of its assets to NGL Energy Partners LP ("NGL Energy"). The contributed assets included SemStream, L.P.'s primary operating assets, excluding those of its residential operations. The accompanying financial statements of the SemStream Non-Residential Division reflect the historical activity of the operations that were contributed to NGL Energy. The SemStream Non-Residential Division will hereinafter be referred to as "SemStream".

        SemGroup Corporation is a Delaware Corporation with its headquarters in Tulsa, Oklahoma. SemGroup Corporation is the successor entity of SemGroup, L.P., which was an Oklahoma limited partnership. The term "SemGroup" refers to SemGroup Corporation, SemGroup, L.P., and their other controlled subsidiaries.

        These financial statements have been prepared in accordance with accounting principles generally accepted in the United States.

Operations

        SemStream's operations included the following:

Bankruptcy

        On July 22, 2008 (the "Petition Date"), SemGroup, L.P. and SemStream, L.P. filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. While in bankruptcy, SemGroup, L.P. filed a Plan of Reorganization with the court, which was confirmed on October 28, 2009. The Plan of Reorganization determined, among other things, how pre-Petition Date obligations would be settled, the equity structure of the reorganized company upon emergence, and the financing arrangements upon emergence. SemGroup Corporation and SemStream, L.P. emerged from bankruptcy protection on November 30, 2009 (the "Emergence Date").

        The accompanying financial statements of SemStream include its activities prior to emergence from bankruptcy and its activities subsequent to emergence from bankruptcy. As described in Note 3, SemStream applied fresh-start reporting on the Emergence Date. As a result, the financial statements of SemStream subsequent to the Emergence Date are not comparable to its financial statements prior to the Emergence Date.

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SemStream Non-Residential Division

Notes to Financial Statements (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

        USE OF ESTIMATES—The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures in the financial statements. SemStream's significant estimates include, but are not limited to: (1) allowances for doubtful accounts receivable; (2) estimated useful lives of assets, which impacts depreciation; (3) estimated fair values of long-lived assets recorded in fresh-start reporting; (4) estimated fair values of long-lived assets used in impairment tests; (5) fair values of derivative instruments; and (6) accrual and disclosure of contingent losses. Although management believes these estimates are reasonable, actual results could differ materially from these estimates.

        FRESH-START REPORTING—SemGroup adopted fresh-start reporting on the Emergence Date. In connection with fresh-start reporting, SemStream recorded its assets and liabilities at fair value at the Emergence Date.

        CASH AND CASH EQUIVALENTS—Cash includes currency on hand and demand and time deposits with banks or other financial institutions. Cash equivalents include highly liquid investments with maturities of three months or less at the date of purchase.

        ACCOUNTS RECEIVABLE—Accounts receivable are reported net of the allowance for doubtful accounts. SemStream's assessment of the allowance for doubtful accounts is based on several factors, including the overall creditworthiness of its customers, existing economic conditions, and the amount and age of past due accounts. SemStream entered into netting arrangements with certain counterparties to help mitigate credit risk. Receivables subject to netting are presented as gross receivables (with the related accounts payable also presented gross) until such time as the balances are settled. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. At the Emergence Date, as part of fresh-start reporting, SemStream recorded accounts receivable at fair value. This was accomplished by reducing the allowance for doubtful accounts to $-0- and recording a corresponding reduction to accounts receivable.

        INVENTORIES—Inventories primarily consist of natural gas liquids. Inventories are valued at the lower of cost or market, with cost generally determined using the weighted-average method, although as described above, inventory was adjusted to fair value at November 30, 2009 upon adoption of fresh-start reporting. The cost of inventory includes applicable transportation costs.

        Prior to emergence from bankruptcy, SemStream's policy was to measure the fair value of inventory, for the purpose of determining whether to lower the carrying value from cost to market, on a monthly basis. Subsequent to emergence from bankruptcy, SemStream's policy is to measure the fair value of inventory, for the purpose of determining whether to lower the carrying value from cost to market, on a quarterly basis.

        SemStream enters into exchanges with third parties whereby it acquires products that differ in location, grade, or delivery date from products SemStream has available for sale. These exchanges are valued at cost, and although a transportation, location or product differential may be recorded, generally no significant gain or loss is recognized.

        PROPERTY, PLANT AND EQUIPMENT—Property, plant and equipment is recorded at cost (although, as described above, property, plant and equipment was adjusted to fair value at

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SemStream Non-Residential Division

Notes to Financial Statements (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

November 30, 2009 upon adoption of fresh-start reporting). SemStream capitalizes costs that extend or increase the future economic benefits of property, plant and equipment, and expenses maintenance costs that do not. When assets are disposed of, their cost and related accumulated depreciation are removed from the balance sheet, and any resulting gain or loss is recorded within operating expenses in the statements of operations.

        Depreciation is calculated primarily on the straight-line method over the following estimated useful lives:

Storage and terminal facilities

  10 - 25 years

Pipelines and related facilities

  20 years

        LINEFILL—Pipelines and storage facilities generally require a minimum volume of product in the system to enable the system to operate. Such product, known as linefill, is generally not available to be withdrawn from the system. Linefill owned by SemStream in facilities operated by SemStream is recorded at historical cost, is included in property, plant and equipment on the balance sheets, and is not depreciated. SemStream also owned linefill in third party facilities, which is included in inventory on the balance sheets.

        IMPAIRMENT OF LONG-LIVED ASSETS—SemStream tests long-lived asset groups for impairment when events or circumstances indicate that the net book value of the asset group may not be recoverable. SemStream tests an asset group for impairment by estimating the undiscounted cash flows expected to result from its use and eventual disposition. If the estimated undiscounted cash flows are lower than the net book value of the asset group, SemStream estimates the fair value of the asset group and records a reduction to the net book value of the assets and a corresponding impairment loss.

        GOODWILL—SemStream tests goodwill for impairment on an annual basis, or more often if circumstances warrant, by estimating the fair value of its assets and comparing this to the net book value of its assets. If fair value is less than net book value, SemStream estimates the implied fair value of goodwill, reduces the book value of the goodwill to the implied fair value, and records a corresponding impairment loss. Prior to the Emergence Date, SemStream's policy was to test goodwill for impairment on December 31 of each year. Subsequent to the Emergence Date, SemStream's policy is to test goodwill for impairment on October 1 of each year. For the October 1, 2010 impairment test, SemStream developed estimates of future cash flows for a period of 15 years, and also developed an estimated terminal value using an assumed 3% growth rate. Estimated cash flows were then discounted to present value using a rate of 9.36%.

        OTHER INTANGIBLE ASSETS—Other intangible assets consist of customer relationships and contracts. Prior to the Emergence Date, intangible assets were generally amortized on a straight-line basis over the expected period of benefit. Subsequent to the Emergence Date, intangible assets are generally amortized on an accelerated basis over the estimated period of benefit. These assets could be subject to impairment in the event relationships are not maintained with the customers to which the assets relate. SemStream recorded intangible asset amortization expense of $2.9 million for the year ended December 31, 2010, $0.2 million for the month ended December 31, 2009, $0.6 million for the eleven months ended November 30, 2009, and $0.8 million for the year ended December 31, 2008. At

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SemStream Non-Residential Division

Notes to Financial Statements (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

December 31, 2010, amortization of other intangible assets was scheduled to be as follows (in thousands):

For the year ending:

       

December 31, 2011

  $ 2,268  

December 31, 2012

    1,916  

December 31, 2013

    1,627  

December 31, 2014

    1,366  

December 31, 2015

    1,115  

Thereafter

    5,631  
       

Total scheduled amortization expense

  $ 13,923  
       
       

        DERIVATIVE INSTRUMENTS AND MARGIN DEPOSITS—SemStream generally records the fair value of derivative instruments on its balance sheets and the change in fair value as an increase or decrease to product revenue. The fair values of derivatives and related margin deposits at December 31, 2010 and 2009 are reported within current assets or current liabilities on the balance sheets. Margin deposits have generally not been netted against derivative assets or liabilities at December 31, 2010 and 2009.

        The fair value of a derivative contract is determined based on the nature of the transaction and the market in which the transaction was executed. Quoted market prices, when available, are used to value derivative transactions. In situations where quoted market prices are not readily available, SemStream estimates the fair value using other valuation techniques that reflect the best information available under the circumstances. Fair value measurements of derivative assets include consideration of counterparty credit risk. Fair value measurements of derivative liabilities include consideration of SemGroup's creditworthiness.

        SemStream has elected "normal purchase" and "normal sale" treatment for certain commitments to purchase or sell petroleum products at future dates. This election is only available when a transaction is expected to result in physical delivery of product over a reasonable period in the normal course of business and is not expected to be net settled. Agreements accounted for under this election are not recorded at fair value; instead, the transaction is recorded when title to the product is transferred.

        INTERCOMPANY ACCOUNTS—SemStream participated in SemGroup's cash management program. Under this program, cash SemStream received from customers was transferred to SemGroup on a regular basis; when SemStream remitted payments to suppliers, SemGroup transferred cash to SemStream to cover the payments. In addition, SemGroup incurred certain expenses on SemStream's behalf that are reported within SemStream's statements of operations.

        SemStream recorded transactions with SemGroup and its other controlled subsidiaries to intercompany accounts. When SemStream's intercompany accounts were in a net receivable position, the balance has been reported as a reduction to equity on the balance sheet. When SemStream's intercompany accounts were in a net payable position, the balance has been reported as a current liability on the balance sheet. In the statements of cash flows, SemStream has reported the net change in the intercompany accounts as a financing cash flow within "net contributions from (distributions to)

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SemStream Non-Residential Division

Notes to Financial Statements (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

SemGroup". SemStream has reported the net change in equity associated with these transactions as "net contributions from SemGroup" or "net distributions to SemGroup" in the statements of changes in net parent equity.

        SemStream's intercompany accounts were in a net receivable position of $13.5 million at December 31, 2010. SemStream has reported this balance as a reduction to equity on the balance sheet, as SemStream does not expect to collect these intercompany receivables. SemStream's intercompany accounts were in a net payable position of $5.0 million at December 31, 2009.

        PAYABLES TO PRE-PETITION CREDITORS—SemGroup's Plan of Reorganization specified the total amount of consideration it would provide to all pre-petition creditors in settlement of their claims. SemGroup has not yet completed the process of disbursing funds to settle pre-petition claims, as it has not yet completed the process of resolving all of the claims. Upon emergence from bankruptcy, SemStream recorded a liability to reflect its obligations to these claimants pursuant to the Plan of Reorganization.

        CONTINGENT LOSSES—SemStream records a liability for a contingent loss when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. SemStream records attorneys' fees incurred in connection with a contingent loss at the time the fees are incurred. SemStream does not record liabilities for attorneys' fees that are expected to be incurred in the future.

        ASSET RETIREMENT OBLIGATIONS—Asset retirement obligations include legal or contractual obligations associated with the retirement of long-lived assets, such as requirements to incur costs to dispose of equipment or to remediate the environmental impacts of the normal operation of the assets. SemStream records liabilities for asset retirement obligations when a known obligation exists under current law or contract and when a reasonable estimate of the value of the liability can be made.

        REVENUE RECOGNITION—Sales of product are recognized at the time title to the product transfers to the purchaser. Any transportation costs incurred to ship product on third-party infrastructure are included in the price of product sold to customers, and are included within product revenues and costs of goods sold. Taxes collected from customers and remitted to governmental authorities are recorded on a net basis (excluded from revenue).

        SemStream routinely enters into transactions to purchase inventory from, and sell inventory to, the same counterparty. Revenues for such transactions that are entered into in contemplation of one another are recorded net of costs of products sold. SemStream accounted for $118.9 million of such transactions on a net basis during the year ended December 31, 2010, $3.6 million of such transactions on a net basis during the month ended December 31, 2009, $10.2 million of such transactions on a net basis during the eleven months ended November 30, 2009, and $222.6 million of such transactions on a net basis during the year ended December 31, 2008.

        INTEREST EXPENSE—The interest expense reported in SemStream's statements of operations consists of letter of credit fees. SemGroup has been a borrower on several corporate credit agreements (and SemStream's assets served as collateral under these agreements), but SemGroup did not allocate this debt to its subsidiaries. SemGroup did not charge SemStream interest on the balances in its intercompany accounts.

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SemStream Non-Residential Division

Notes to Financial Statements (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        OTHER INCOME—Other income in the statement of operations for the year ended December 31, 2010 includes a $1.2 million gain on the settlement of a dispute related to the cancellation of a contract by a counterparty during 2008, and also includes a gain of $1.2 million related to the settlement of a dispute related to certain transportation fees charged to SemStream by an unaffiliated party during the years 2005-2009.

        INCOME TAXES—SemStream, L.P. is a pass-through entity for federal and state income tax purposes. Its earnings are allocated to its owners, who are responsible for any related income taxes. Because of this, no provision for income taxes is reported in the accompanying statements of operations.

        REORGANIZATION ITEMS—As described in Note 1, SemGroup and SemStream, L.P. operated as debtors-in-possession subject to the jurisdiction of the bankruptcy court during the period from the Petition Date to the Emergence Date. Revenues, expenses, realized gains and losses, and provisions for losses resulting from the reorganization and restructuring of the business are reported as reorganization items in the statements of operations. The effects of the adjustments to the reported amounts of assets and liabilities resulting from the adoption of fresh-start reporting are reported within reorganization items in the statement of operations for the eleven months ended November 30, 2009.

        SUBSEQUENT EVENTS—SemStream has evaluated subsequent events for accrual or disclosure in these financial statements through November 3, 2011, which is the date these financial statements were issued.

3. REORGANIZATION

        On July 22, 2008, SemGroup and many of its affiliates (including SemStream, L.P.), filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Certain claims against SemGroup in existence prior to the filing of the petitions for relief under the federal bankruptcy laws were stayed while SemGroup continued business operations as a debtor-in-possession. SemGroup received approval from the court to pay or otherwise honor certain of its obligations incurred before the Petition Date. The court also approved SemGroup's use of cash to meet post-Petition Date obligations.

        While in bankruptcy, SemGroup filed a Plan of Reorganization with the court, which was confirmed on October 28, 2009. The Plan of Reorganization determined, among other things, how pre-Petition Date obligations would be settled, SemGroup's equity structure upon emergence, and SemGroup's financing arrangements upon emergence.

Determination of reorganization value

        An essential element in negotiating a reorganization plan with the various classes of creditors is the determination of reorganization value by the parties in interest. In the event that the parties in interest cannot agree on the reorganization value, the court may be called upon to determine the reorganization value of the entity before a plan of reorganization can be confirmed.

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SemStream Non-Residential Division

Notes to Financial Statements (Continued)

3. REORGANIZATION (Continued)

        During SemGroup's reorganization process, a reorganization value was proposed. This reorganization value was ultimately agreed to by the creditors and confirmed by the court. The proposed reorganization value was determined by applying the following valuation methods:

        After completing this analysis, the reorganization value of SemGroup was determined to be $1.5 billion. This proposed reorganization value was determined using numerous projections and assumptions. These estimates are subject to significant uncertainties, many of which are beyond SemGroup's control, including, but not limited to, the following:

        The use of different estimates could have resulted in a materially different proposed reorganization value, and there can be no assurance that actual results will be consistent with the estimates that were used to determine the proposed reorganization value. The reorganization value confirmed by the court was utilized in the application of fresh-start reporting.

Valuation of SemStream's assets and liabilities

        SemGroup determined that $253.8 million of its reorganization value was attributable to SemStream. Accordingly, SemStream recorded individual assets and liabilities based on their estimated fair values at the Emergence Date.

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SemStream Non-Residential Division

Notes to Financial Statements (Continued)

3. REORGANIZATION (Continued)

November 30, 2009 balance sheet

        The following table shows the effects of the emergence from bankruptcy on SemStream's November 30, 2009 balance sheet (in thousands):

 
  Prior to
Emergence
  Reorganization
Adjustments
  Fresh Start
Adjustments
  Subsequent to
Emergence
 

ASSETS

                         

Current assets:

                         

Accounts receivable

  $ 40,330   $   $   $ 40,330  

Receivable from affiliate

    1,799     (1,799) (a)        

Inventories

    100,529         36,502 (h)   137,031  

Derivative assets

    2,894         1,700 (h)   4,594  

Margin deposits

    22,379             22,379  

Other current assets

    11,994             11,994  
                   

Total current assets

    179,925     (1,799 )   38,202     216,328  
                   

Property, plant and equipment, net

    37,826         4,281 (h)   42,107  

Goodwill

    2,425         47,646 (h)   50,071  

Other intangible assets, net

    3,288         13,712 (h)   17,000  

Other assets

    3,886             3,886  
                   

Total assets

  $ 227,350   $ (1,799 ) $ 103,841   $ 329,392  
                   
                   

LIABILITIES AND NET PARENT EQUITY (DEFICIT)

                         

Current liabilities:

                         

Accounts payable

  $ 43,565   $ (534) (b) $   $ 43,031  

Advances from parent

    476,451     (476,451) (c)        

Derivative liabilities

    15,943     (408) (d)   4,908 (h)   20,443  

Payables to pre-petition creditors              

        10,202 (e)       10,202  

Other current liabilities

    1,768             1,768  
                   

Total current liabilities

    537,727     (467,191 )   4,908     75,444  
                   

Liabilities subject to compromise

    25,750     (25,750) (f)        

Other noncurrent liabilities

    160             160  

Net parent equity (deficit):

                         

Net parent equity (deficit)—Predecessor

    (336,287 )   336,287 (g)        

Net parent equity—Successor

        154,855 (g)   98,933 (i)   253,788  
                   

Net parent equity (deficit)

    (336,287 )   491,142     98,933     253,788  
                   

Total liabilities and net parent equity (deficit)

  $ 227,350   $ (1,799 ) $ 103,841   $ 329,392  
                   
                   

(a)
Prior to emergence from bankruptcy, SemStream had a receivable from SemCanada Crude Company, which is a wholly-owned subsidiary of SemGroup that applied for bankruptcy protection in Canada in July 2008 and emerged from bankruptcy on November 30, 2009, concurrent with the emergence of SemGroup and SemStream. SemCanada Crude Company was not under SemGroup's control during the bankruptcy.

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3. REORGANIZATION (Continued)

(b)
SemStream elected not to cancel certain contracts that were in effect prior to the Petition Date. For these contracts, SemStream was required to make payments to the counterparties to cure defaults on the contracts. These payments were made by SemGroup upon emergence from bankruptcy.

(c)
SemStream's liabilities to SemGroup and its controlled subsidiaries were extinguished pursuant to the Plan of Reorganization.

(d)
Reflects the transfer to SemGroup of a commodity derivative contract.

(e)
SemGroup's Plan of Reorganization specified the total amount of consideration it would provide to all pre-petition creditors in settlement of their claims. SemGroup has not yet completed the process of disbursing funds to settle pre-petition claims, as it has not yet completed the process of resolving all of the claims. Upon emergence from bankruptcy, SemStream recorded a liability to reflect its obligations to these claimants pursuant to the Plan of Reorganization.

(f)
Represents the transfer to SemGroup of liabilities subject to compromise, pursuant to the Plan of Reorganization.

(g)
Reflects the cancellation of predecessor equity and the issuance of successor equity.

(h)
Reflects the adjustments to the recorded values of assets and liabilities resulting from fresh-start reporting.

(i)
Reflects the reorganization items gain resulting from fresh-start reporting.

Reorganization items

        The reorganization items gain (loss) shown on the statements of operations consists of the following (in thousands):

 
  Prior to Emergence  
 
  Eleven Months
Ended
November 30,
2009
  Year
Ended
December 31,
2008
 

Gain on asset revaluation in fresh-start reporting(a)

  $ 98,933   $  

Professional fees(b)

    (68,120 )   (24,430 )

Uncollectable accounts expense(c)

    (6,213 )    

Adjustment to liabilities subject to compromise(d)

    4,100      

Employment costs(e)

    (2,059 )   (817 )

Other

    (171 )    
           

Total reorganization items gain (loss)

  $ 26,470   $ (25,247 )
           
           

(a)
SemStream revalued its assets and liabilities in fresh-start reporting, and recorded a reorganization gain for the increase in fair value of the net assets over the previously recorded values.

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3. REORGANIZATION (Continued)

(b)
SemGroup incurred a variety of professional fees related to the restructuring of the business, including, among others:

legal fees related to the reorganization process, including those related to bankruptcy court filings and hearings, negotiation of credit agreements, settlements of disputes with claimants, and other matters;

general management consulting services related to the disposal of assets, the reconciliation and negotiation of pre-petition claims, preparation for emergence from bankruptcy, and other matters;

valuation advisory fees for the determination of the reorganization value of the business required for the Plan of Reorganization and the valuation of long-lived assets required by fresh-start reporting;

accounting fees for assistance with fresh-start reporting and preparation for public company financial reporting obligations; and

fees paid to the United States Trustee.

SemGroup allocated a portion of these fees to SemStream, based on the reorganization value of SemStream relative to the total reorganization value of SemGroup's United States subsidiaries that emerged from bankruptcy.

(c)
Represents the write-off of receivables in situations where SemStream believed the customer non-payment was related to the bankruptcy.

(d)
Represents refinements to the estimated amount of valid claims by pre-petition creditors. During 2008, SemStream recorded an estimated loss for the total amount of valid claims subject to compromise. During 2009, SemStream refined this estimate as it reviewed the claims, and reversed a $4.1 million loss that had been recorded to general and administrative expense in 2008.

(e)
Employment costs include severance related to the termination of employment relationships and bonuses paid to retain personnel during the reorganization.

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4. PROPERTY, PLANT AND EQUIPMENT

        Property, plant and equipment consists of the following (in thousands):

 
  Subsequent to Emergence  
 
  December 31,
2010
  December 31,
2009
 

Land

  $ 3,006   $ 3,006  

Pipelines and related facilities

    4,277     2,741  

Storage and terminal facilities

    39,895     35,515  

Linefill

    1,170      

Other property and equipment

    931     846  

Construction-in-progress

    1,091     879  
           

Property, plant and equipment, gross

    50,370     42,987  

Accumulated depreciation

    (2,342 )   (175 )
           

Property, plant and equipment, net

  $ 48,028   $ 42,812  
           
           

        SemStream recorded depreciation expense of $2.2 million for the year ended December 31, 2010, $0.2 million for the month ended December 31, 2009, $3.2 million for the eleven months ended November 30, 2009, and $3.1 million for the year ended December 31, 2008.

        SemStream includes within the cost of property, plant and equipment interest costs incurred by SemGroup while an asset is being constructed. SemStream capitalized $0.1 million of interest costs during the year ended December 31, 2008. Since the related debt was recorded by SemGroup, rather than by SemStream, no interest expense related to SemGroup's debt is reported in SemStream's statements of operations. The increase in the value of property, plant and equipment associated with capitalized interest is reported as an increase to SemStream's net parent equity.

5. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK

Commodity derivative contracts

        SemStream's results of operations and cash flows are impacted by changes in market prices for petroleum products. This exposure to commodity price risk was managed, in part, by entering into various commodity derivatives.

        During 2009 and 2010, SemStream managed commodity price risk by limiting its net open positions subject to outright price risk and basis risk resulting from grade, location or time differences. SemStream did so by selling and purchasing similar quantities of natural gas liquids with purchase and sale transactions for current or future delivery, by entering into future delivery and purchase obligations with futures contracts or other commodity derivatives and employing its storage and transportation assets. At times SemStream hedged its natural gas liquids commodity price exposure with derivatives on commodities other than natural gas liquids due to the limited size of the market for natural gas liquids derivatives. In addition, physical transaction sale and purchase strategies were intended to lock in positive margins for SemStream, e.g., the sales price was sufficient to cover purchase costs, any other fixed and variable costs and SemStream's profit. All marketing activities were subject to SemGroup's risk management policy, which established limits to manage risk and mitigate financial exposure.

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Notes to Financial Statements (Continued)

5. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK (Continued)

        During 2010 and 2009, SemStream's commodity derivatives were comprised of natural gas liquids swaps, forward contracts and futures contracts. These are defined as follows:

        Swaps—Over the counter transactions where a floating price, basis or index is exchanged for a fixed (or a different floating) price, basis, or index at a preset schedule in the future according to an agreed upon formula.

        Forward contracts—Over the counter contracts to buy or sell a commodity at an agreed upon future date. The buyer and seller agree on specific terms (price, quantity, delivery period, and location) and conditions at the inception of the contract.

        Futures contracts—Exchange traded contracts to buy or sell a commodity. These contracts are standardized by the exchange in terms of quality, quantity, delivery period and location for each commodity.

        The table below summarizes the balances of derivative assets and liabilities at December 31, 2010 and 2009 (in thousands):

 
  Subsequent to Emergence  
 
  December 31, 2010   December 31, 2009  
 
  Level 1   Level 2   Level 3   Netting   Total   Level 1   Level 2   Level 3   Netting   Total  

Assets

  $ 84   $ 1,785   $ 2,498   $   $ 4,367   $   $ 1,605   $ 982   $ (27 ) $ 2,560  

Liabilities

   
2,123
   
6,631
   
4,664
   
   
13,418
   
   
1,193
   
24,638
   
(27

)
 
25,804
 
                                           

Net assets (liabilities) at fair value

  $ (2,039 ) $ (4,846 ) $ (2,166 ) $   $ (9,051 ) $   $ 412   $ (23,656 ) $   $ (23,244 )
                                           
                                           

        "Level 1" measurements were obtained using unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. These include futures contracts that are traded on an exchange.

        "Level 2" measurements use as inputs market observable and corroborated prices for similar derivative contracts. Assets and liabilities classified as Level 2 include over-the-counter (OTC) traded forward contracts and swaps.

        "Level 3" measurements were obtained using information from a pricing service and internal valuation models incorporating observable and unobservable market data. These include commodity derivatives, such as forward contracts and swaps for which there is not a highly liquid market and therefore are not included in Level 2 above.

        Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. SemStream's assessment of the significance of a particular input to the measurement requires judgment, and may affect the valuation of assets and liabilities and their placement within the fair value levels.

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Notes to Financial Statements (Continued)

5. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK (Continued)

        The following table reconciles changes in the fair value of commodity derivatives classified as Level 3 in the fair value hierarchy (in thousands):

 
  Subsequent to Emergence    
  Prior to
Emergence
 
 
  Year
Ended
December 31,
2010
  Month
Ended
December 31,
2009
   
  Eleven Months
Ended
November 30,
2009
 
 
   
 
 
   
 
 
   
 

Beginning balance

  $ (23,656 ) $ (16,071 )     $ 11,335  

Transfers out of Level 3(*)

    4,072              

Total gain or loss (realized and unrealized) included in product revenues

    (6,270 )   (13,587 )       (18,603 )

Settlements

    23,688     6,002         (5,596 )

Fresh-start and plan effect adjustments

                (3,207 )
                   

Ending balance

  $ (2,166 ) $ (23,656 )     $ (16,071 )
                   
                   

Amount of total loss included in earnings for the period attributable to the change in unrealized loss relating to assets and liabilities still held at the reporting date

  $ (6,270 ) $ (13,587 )     $ (18,603 )

(*)
SemStream's policy is to recognize transfers in and transfers out as of the beginning of the reporting period.

        The following table sets forth the notional quantities for derivative instruments entered into during the periods indicated (amounts in thousands of barrels):

 
  Subsequent to Emergence    
  Prior to Emergence  
 
  Year
Ended
December 31,
2010
  Month
Ended
December 31,
2009
   
  Eleven Months
Ended
November 30,
2009
 
 
   
 
 
   
 
 
   
 

Sales

    9,884     720         8,923  

Purchases

    8,797     345         3,784  

        Realized and unrealized losses from SemStream's commodity derivatives were recorded to product revenue in the following amounts (in thousands):

 
  Subsequent to Emergence    
  Prior to Emergence  
 
  Year
Ended
December 31,
2010
  Month
Ended
December 31,
2009
   
  Eleven Months
Ended
November 30,
2009
 
 
   
 
 
   
 
 
   
 

Commodity Contracts

  $ (10,215 ) $ (13,871 )     $ (32,522 )

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Notes to Financial Statements (Continued)

5. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK (Continued)

Transfer of derivative positions in July 2008

        During July 2008, SemStream transferred to SemGroup certain of its open derivative positions and related margin deposits, and recorded a corresponding increase of $105.3 million to its intercompany liabilities. SemGroup subsequently transferred these derivatives (along with certain derivatives entered into by its other subsidiaries) to a third party, and SemGroup recorded a loss of $143 million on this third-party transaction. The losses on these derivatives prior to their transfer to SemGroup are reflected in SemStream's statements of operations, and the losses subsequent to the transfer of these derivatives to SemGroup are not reflected in SemStream's statements of operations.

Concentrations of risk

        Customers from which SemStream generated more than 10% of its total revenue included the following (in thousands):

 
  Subsequent to Emergence    
  Prior to Emergence  
 
  Year
Ended
December 31, 2010
  Month
Ended
December 31, 2009
   
  Eleven Months
Ended
November 30, 2009
  Year
Ended
December 31, 2008
 
 
   
 
 
   
 
 
   
  Percentage
of Total
Revenues
   
  Percentage
of Total
Revenues
   
   
  Percentage
of Total
Revenues
   
  Percentage
of Total
Revenues
 
 
  Revenues   Revenues    
  Revenues   Revenues  
 
   
 

Customer A

  $ 83,422     12 % $ 16,330     26 %     $ 65,728     16 % $ 151,964     10 %

Customer B

    *     *   $ 9,300     15 %     $ 56,394     13 %   *     *  

Customer C

    *     *   $ 7,250     11 %       *     *     *     *  

Customer D

    *     *   $ 6,734     11 %       *     *     *     *  

Customer E

    *     *     *     *         *     *   $ 191,936     13 %

*
Revenues from this customer were less than 10% of total revenue for the period

        SemStream's customers with accounts receivable balances greater than 10% of its total accounts receivable included the following (in thousands):

 
  Subsequent to Emergence  
 
  December 31, 2010   December 31, 2009  
 
  Accounts
Receivable
  Percentage
of Total
Accounts
Receivable
  Accounts
Receivable
  Percentage
of Total
Accounts
Receivable
 

Customer F

  $ 11,734     14 %   *     *  

Customer G

  $ 10,516     13 %   *     *  

Customer B

    *     *   $ 9,772     23 %

Customer A

    *     *   $ 5,498     13 %

*
Accounts receivable trade balance at December 31st was less than 10% of reported accounts receivable balance.

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Notes to Financial Statements (Continued)

5. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK (Continued)

        Suppliers from which SemStream's purchases represented more than 10% of SemStream's total costs of products sold included the following (in thousands):

 
  Subsequent to Emergence    
  Prior to Emergence  
 
  Year
Ended
December 31, 2010
  Month
Ended
December 31, 2009
   
  Eleven Months
Ended
November 30, 2009
  Year
Ended
December 31, 2008
 
 
   
 
 
   
 
 
   
  Percentage
of Total
Costs of
Products Sold
   
  Percentage
of Total
Costs of
Products Sold
   
   
  Percentage
of Total
Costs of
Products Sold
   
  Percentage
of Total
Costs of
Products Sold
 
 
   
   
   
   
   
 
 
  Purchases   Purchases    
  Purchases   Purchases  
 
   
 

Supplier A**

  $ 96,065     14 % $ 17,640     23 %     $ 74,995     18 % $ 173,031     10 %

Supplier B

  $ 75,708     11 %   *     *       $ 47,162     11 %   *     *  

Supplier C

  $ 71,008     10 %   *     *       $ 43,443     10 %   *     *  

Supplier D***

    *     *   $ 20,556     27 %     $ 42,137     10 %   *     *  

Supplier E

    *     *     *     *         *     *   $ 522,667     31 %

Supplier F

    *     *     *     *         *     *   $ 231,562     14 %

*
Purchases for the period was less than 10% of total costs of products sold.

**
Supplier A is the same entity as Customer F in the tables above.

***
Supplier D is the same entity as Customer G in the tables above.

        As described in Note 9, SemStream also generated significant revenues and expenses during the periods from 2008 through 2010 from other subsidiaries of SemGroup.

6. COMMITMENTS AND CONTINGENCIES

Bankruptcy matters

(a)
Confirmation order appeals

        Manchester Securities appeal.    On October 21, 2009, Manchester Securities Corporation, a creditor of SemGroup Holdings, L.P. (a subsidiary of SemGroup), filed an objection to the Plan of Reorganization. In the objection, Manchester argued that the Plan of Reorganization should not be confirmed because it did not provide for an alleged $50 million claim of SemGroup Holdings, L.P. against SemCrude Pipeline, L.L.C. (another subsidiary of SemGroup). On October 28, 2009, the bankruptcy court overruled the objection and entered the confirmation order approving the Plan of Reorganization. On November 4, 2009, Manchester filed a notice of appeal of the confirmation order. On December 4, 2009, Manchester's appeal was docketed in the United States District Court for the District of Delaware.

        SemGroup filed a motion to dismiss the appeal as equitably moot. On February 18, 2011, the District Court granted SemGroup's motion to dismiss the appeal. On March 22, 2011, Manchester filed a notice to appeal this order. While SemGroup believes that this action is without merit and is vigorously defending this matter on appeal, an adverse ruling on this action could have a material adverse impact.

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6. COMMITMENTS AND CONTINGENCIES (Continued)

        Luke Oil appeal.    On October 21, 2009, Luke Oil Company, C&S Oil/Cross Properties, Inc., Wayne Thomas Oil and Gas and William R. Earnhardt Company (collectively, "Luke Oil") filed an objection to the Plan of Reorganization "to the extent that the Plan of Reorganization may alter, impair, or otherwise adversely affect Luke Oil's legal rights or other interests." On October 28, 2009, the bankruptcy court overruled the Luke Oil objection and entered the confirmation order. On November 6, 2009, Luke Oil filed a notice of appeal. On December 23, 2009, Luke Oil's appeal was docketed in the United States District Court for the District of Delaware. SemGroup filed a motion to dismiss the appeal as equitably moot. Luke Oil has filed a motion to stay the briefing on SemGroup's motion to dismiss. On February 18, 2011, the District Court denied the stay motion and ordered the parties to complete briefing. While SemGroup believes that this action is without merit and is vigorously defending this matter on appeal, an adverse ruling on this action could have a material adverse impact.

(b)
Claims reconciliation process

        A large number of parties have made claims against SemStream for obligations alleged to have been incurred prior to the Petition Date. On September 15, 2010, the bankruptcy court entered an order estimating the contingent, unliquidated and disputed claims and authorizing distributions to holders of allowed claims. Pursuant to that order, SemGroup has begun making distributions to the claimants. SemGroup continues to attempt to settle unresolved claims.

        Pursuant to the Plan of Reorganization, SemGroup committed to settle authorized and allowed bankruptcy claims by paying a specified amount of cash, issuing a specified number of warrants, and issuing a specified number of shares of SemGroup Corporation common stock. SemGroup does not believe the resolution of the remaining outstanding claims will exceed the total amount of consideration established under the Plan of Reorganization for all claimants; instead, the resolutions of the remaining claims in some cases will impact the relative share of the established pool of common stock and warrants that certain claimants receive.

        However, under certain circumstances SemGroup could be required to pay additional funds to settle the specified group of claims to be settled with cash. Pursuant to the Plan of Reorganization, a specified amount of restricted cash was set aside at the Emergence Date, which SemGroup expects to be sufficient to settle this group of claims. Since the Emergence Date, SemGroup has made significant progress in resolving these claims, and continues to believe that the cash set aside at the Emergence Date will be sufficient to settle these claims. However, SemGroup has not yet reached a resolution of all of these claims, and if the total settlement amount of all of these claims exceeds the specified amount, SemGroup will be required to pay additional funds to satisfy the total settlement amount for this specified group of claims. If this were to become probable of occurring, SemGroup would be required to record a liability and a corresponding expense, and SemStream could be required to share in this expense.

Environmental

        SemStream may from time to time experience leaks of petroleum products from its facilities, as a result of which it may incur remediation obligations or property damage claims. In addition, SemStream is subject to numerous environmental regulations. Failure to comply with these regulations could result in the assessment of fines or penalties by regulatory authorities.

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Notes to Financial Statements (Continued)

6. COMMITMENTS AND CONTINGENCIES (Continued)

Asset retirement obligations

        SemStream may be subject to removal and restoration costs upon retirement of their facilities. However, SemGroup does not believe the present value of such obligations under current laws and regulations, after taking into account the estimated lives of the facilities, is material to SemStream's financial position or results of operations.

Other matters

        SemStream is party to various other claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of SemGroup's management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, will not have a material adverse effect on SemStream's financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of SemStream's liabilities may change materially as circumstances develop.

Leases

        SemStream has entered into operating lease agreements for office space, office equipment, land, trucks and tank storage. Future minimum payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year at December 31, 2010 are as follows (in thousands):

 
   
 

For the year ending:

       

December 31, 2011

  $ 858  

December 31, 2012

    825  

December 31, 2013

    808  

December 31, 2014

    806  

December 31, 2015

    230  

Thereafter

    2  
       

Total future minimum lease payments

  $ 3,529  
       
       

        SemStream recorded lease and rental expenses of $4.2 million for the year ended December 31, 2010, $0.4 million for the month ended December 31, 2009, $3.9 million for the eleven months ended November 30, 2009, and $4.4 million for the year ended December 31, 2008.

Purchase and sale commitments

        SemStream routinely entered into agreements to purchase and sell petroleum products at specified future dates. SemStream established a margin for these purchases by entering into various types of physical and financial sales and exchange transactions through which it sought to maintain a position that was substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. SemStream accounted for these commitments as normal purchases and sales,

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6. COMMITMENTS AND CONTINGENCIES (Continued)

and therefore did not record assets or liabilities related to these agreements until the product was purchased or sold. At December 31, 2010, such commitments included the following (in thousands):

 
  Volume
(barrels)
  Value  

Floating price purchases

    1,574   $ 85,765  

Floating price sales

    792   $ 44,786  

        Certain of the commitments shown in the table above relate to agreements to purchase product from a counterparty and to sell a similar amount of product (in a different location) to the same counterparty. Many of the commitments shown in the table above are cancellable by either party, as long as notice is given within the time frame specified in the agreement (generally 30 to 120 days).

        SemStream has also entered into an agreement under which it is obligated to purchase all of the propane produced by a third-party refinery at a price that floats based on market rates. Under one of these agreements, which expires March 31, 2012, SemStream purchased 11.3 million gallons of propane during 2010 for a total price of $14.2 million.

        SemStream has also entered into a long term marketing agreement to market all natural gas liquids produced by a third party's natural gas processing plants. The agreement expires March 31, 2022. SemStream marketed 60.5 million gallons of natural gas liquids at a purchase cost of $77.3 million during 2010 pursuant to this agreement.

7. EMPLOYEE BENEFITS AND EQUITY-BASED COMPENSATION

        SemStream did not directly employ any persons to manage or operate its business, as these functions were performed by employees of SemGroup. At December 31, 2010, SemGroup had approximately 50 employees who were dedicated primarily to the management and operation of SemStream's business. None of these employees were represented by labor unions, and none were subject to collective bargaining agreements.

Equity-based compensation

        Certain of SemGroup's employees who supported SemStream participated in SemGroup's equity-based compensation program. Awards under this program generally represented awards of restricted stock of SemGroup, which were subject to specified vesting periods. SemGroup charged SemStream $0.4 million during the year ended December 31, 2010 related to such equity-based compensation.

Retention awards

        Certain of SemGroup's employees who supported SemStream were granted retention awards by SemGroup. Each award had a specified value that would be payable either in cash or in shares of SemGroup common stock upon vesting. SemGroup charged SemStream $0.6 million during the year ended December 31, 2010 related to these awards.

Defined contribution plan

        Most of the employees of SemGroup who supported SemStream participated in one of SemGroup's defined contribution plans. SemGroup charged SemStream $0.2 million during each of the

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Notes to Financial Statements (Continued)

7. EMPLOYEE BENEFITS AND EQUITY-BASED COMPENSATION (Continued)

year ended December 31, 2010, the eleven months ended November 30, 2009, and the year ended December 31, 2008, for contributions made by SemGroup to this plan.

Allocated employee compensation expenses

        As described in Note 9, SemGroup allocated certain corporate general and administrative expenses to SemStream. These allocated expenses included equity-based compensation, retention awards, and defined contribution plan benefits for corporate employees, and such expenses are in addition to the expenses described above for employees who directly supported SemStream's operations.

Prior to emergence

        Prior to the Petition Date, certain of SemGroup's employees who supported SemStream participated in equity-based compensation programs. These awards were cancelled in the reorganization. Certain other employees participated in a supplemental executive retirement plan, which was terminated on December 31, 2008.

8. SUPPLEMENTAL INFORMATION—STATEMENTS OF CASH FLOWS

        The non-cash reorganization items shown on the statement of cash flows for the eleven months ended November 30, 2009 include a $6.2 million allowance for uncollectable accounts and a $4.1 million gain on adjustments to liabilities subject to compromise.

        As described in Note 3, SemStream transferred certain assets and liabilities to SemGroup on November 30, 2009, pursuant to SemGroup's Plan of Reorganization. This non-cash activity is not reflected in SemStream's statement of cash flows for the eleven months ended November 30, 2009.

9. TRANSACTIONS WITH SEMGROUP

Direct employee expenses

        SemStream did not directly employ any persons to manage or operate its business; these functions were performed by employees of SemGroup. SemGroup charged SemStream $6.7 million during the year ended December 31, 2010, $0.6 million during the month ended December 31, 2009, $5.2 million during the eleven months ended November 30, 2009, and $4.1 million during the year ended December 31, 2008 for direct employee costs. These expenses were recorded to operating expenses and general and administrative expenses in SemStream's statements of operations.

Allocated expenses

        SemGroup incurs expenses to provide certain indirect corporate general and administrative services to its subsidiaries. Such expenses include employee compensation costs, professional fees, and rental fees for office space, among other expenses.

        In 2008 and for the eleven months ended November 30, 2009, SemGroup's corporate general and administrative expenses were allocated to its subsidiaries based on percentages established by SemGroup management. At the beginning of each year, management estimated corporate general and administrative costs and assigned the subsidiaries a flat monthly charge of that amount. From time to time, the monthly charges were reviewed and adjusted. In addition to the flat monthly charge, the

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Notes to Financial Statements (Continued)

9. TRANSACTIONS WITH SEMGROUP (Continued)

subsidiaries would also be allocated a portion of the over or under allocation of actual corporate general and administrative expense from the prior month. This monthly "true up" was based on each subsidiary's year to date allocation as a percentage of the total year to date corporate general and administrative expense.

        Beginning in December 2009, the general and administrative expenses of each corporate department were allocated to the subsidiaries based on criteria such as actual usage, headcount, and estimates of effort or benefit. The method for allocating cost is based on the type of service being provided. For example, internal audit costs are based on an estimate of effort attributable to a subsidiary. In contrast, certain accounting department costs are allocated based on the number of transactions processed for a given subsidiary compared to the total number processed.

        SemGroup charged SemStream $5.0 million during the year ended December 31, 2010, $1.1 million during the month ended December 31, 2009, $2.4 million during the eleven months ended November 30, 2009, and $1.2 million during the year ended December 31, 2008 for such allocated costs. These expenses were recorded to general and administrative expenses in SemStream's statements of operations.

Allocated reorganization expenses

        As described in Note 3, the reorganization items in SemStream's statements of operations include professional fees allocated from SemGroup of $68.0 million for the eleven months ended November 30, 2009 and $24.4 million for the year ended December 31, 2008. The reorganization items in the statements of operations also include employee expenses allocated from SemGroup of $1.4 million for the eleven months ended November 30, 2009 and $0.6 million for the year ended December 31, 2008.

SemGroup credit facilities

        SemGroup was a borrower under various credit agreements during the periods included in these financial statements. SemStream, L.P., along with other subsidiaries of SemGroup, served as a subsidiary guarantor under certain of these agreements. SemGroup did not allocate this debt to its subsidiaries, and SemStream's statements of operations do not include any allocated interest expense. SemGroup did not charge SemStream interest expense on intercompany payables during the years from 2008 through 2010.

        SemStream utilized letters of credit under SemGroup's credit facilities. At December 31, 2010, SemStream had outstanding letters of credit of $81 million. The statements of operations include direct charges from SemGroup for letter of credit usage, which is reported within interest expense.

        Subsequent to the contribution of the SemStream assets to NGL Energy on November 1, 2011, these assets no longer serve as collateral under SemGroup's credit agreements.

Cash management

        SemStream participated in SemGroup's cash management program. Under this program, cash SemStream received from customers was transferred to SemGroup on a regular basis; when SemStream remitted payments to suppliers, SemGroup transferred cash to them to cover the payments. As described in Note 2, such cash transfers were recorded to intercompany accounts.

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Notes to Financial Statements (Continued)

9. TRANSACTIONS WITH SEMGROUP (Continued)

Product purchases and sales

        SemStream routinely entered into purchase and sale transactions with other controlled subsidiaries of SemGroup, including the following:

        The following table summarizes these transactions (amounts in thousands):

 
  Subsequent to Emergence    
  Prior to Emergence  
 
  Year
Ended
December 31,
2010
  Month
Ended
December 31,
2009
   
  Eleven Months
Ended
November 30,
2009
  Year
Ended
December 31,
2008
 
 
   
 
 
   
 
 
   
 

Revenues from SemCrude, L.P.(*)

  $ 35,410   $ 2,952       $ 26,306   $ 104,822  

Revenues from SemCanada Crude Company

  $ 16,811   $ 1,525                  (**)            (**)

Revenues from SemStream, L.P. residential division

  $ 8,089   $ 1,293       $ 5,367   $ 10,333  

Purchases from SemGas, L.P. 

  $ 22,961   $ 1,804       $ 12,893   $ 11,546  

(*)
Certain of the purchases from SemCrude, L.P. were fixed-price forward purchases, which were recorded at fair value at each balance sheet date. The revenue amounts in this table include any unrealized gains and losses on these contracts.

(**)
SemCanada Crude Company was not consolidated by SemGroup during the period between the Petition Date and the Emergence Date, as SemCanada Crude's bankruptcy was administered in a different jurisdiction than that of SemGroup and SemStream, L.P. Transactions with SemCanada Crude Company during the period of time it was not consolidated by SemGroup are not included in table above. SemStream sold $13.8 million and $3.1 million of product to SemCanada Crude during the eleven months ended November 30, 2009 and the period from July 22, 2008 to December 31, 2008, respectively.

10. CONTRIBUTION OF ASSETS AND LIABILITIES TO NGL ENERGY

        On November 1, 2011, SemStream, L.P. contributed many of the assets of the SemStream Non-Residential Division to NGL Energy, including the majority of the inventory, derivative assets, other current assets, property, plant and equipment, goodwill, other intangible assets, and other noncurrent assets. As part of this transaction, SemStream, L.P. also contributed certain of the liabilities of the SemStream Non-Residential Division to NGL Energy, including the derivative liabilities and capital leases. In return for this contribution, SemStream received $93 million of cash from NGL Energy (subject to post-closing adjustments), 8,932,031 common units representing limited partner interests in NGL Energy, and a 7.5% interest in the general partner of NGL Energy. Also as part of this transaction, SemStream agreed to waive its distribution rights on certain of the common units for a specified period of time.

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Unaudited Condensed Balance Sheets

(Dollars in thousands)

 
  June 30,
2011
  December 31,
2010
 

ASSETS

             

Current assets:

             

Accounts receivable

  $ 37,382   $ 81,555  

Inventories

    60,715     103,411  

Derivative assets

    9,273     4,367  

Margin deposits

    5,158     12,570  

Other current assets

    1,733     995  
           

Total current assets

    114,261     202,898  
           

Property, plant and equipment (net of accumulated depreciation of $3,811 at June 30, 2011 and $2,342 at December 31, 2010)

    47,306     48,028  

Goodwill

    50,071     50,071  

Other intangible assets (net of accumulated amortization of $4,213 at June 30, 2011 and $3,077 at December 31, 2010)

    12,787     13,923  

Other assets

    3,042     3,297  
           

Total assets

  $ 227,467   $ 318,217  
           
           

LIABILITIES AND NET PARENT EQUITY

             

Current liabilities:

             

Accounts payable

  $ 38,191   $ 73,530  

Derivative liabilities

    12,836     13,418  

Other current liabilities

    2,195     3,426  
           

Total current liabilities

    53,222     90,374  
           

Other noncurrent liabilities

    167     167  

Commitments and contingencies (Note 3)

             

Net parent equity

    174,078     227,676  
           

Total liabilities and net parent equity

  $ 227,467   $ 318,217  
           
           

   

The accompanying notes are an integral part of these unaudited condensed financial statements.

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Unaudited Condensed Statements of Operations

(Dollars in thousands)

 
  Six Months
Ended June 30,
2011
  Six Months
Ended June 30,
2010
 

Revenues, including revenues from affiliates (Note 5):

             

Product sales

  $ 359,809   $ 343,326  

Other

    674     3,218  
           

Total revenues

    360,483     346,544  

Expenses, including expenses from affiliates (Note 5):

   
 
   
 
 

Costs of products sold, exclusive of depreciation and amortization shown below

    355,524     332,355  

Operating

    4,436     3,948  

General and administrative

    4,562     4,402  

Depreciation and amortization

    2,623     2,495  
           

Total expenses

    367,145     343,200  
           

Operating income (loss)

    (6,662 )   3,344  

Other expenses (income):

   
 
   
 
 

Interest expense

    1,364     1,778  

Other expense (income), net

    27     (2,422 )
           

Total other expenses (income), net

    1,391     (644 )
           

Net income (loss)

  $ (8,053 ) $ 3,988  
           
           

   

The accompanying notes are an integral part of these unaudited condensed financial statements.

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Unaudited Condensed Statements of Cash Flows

(Dollars in thousands)

 
  Six Months
Ended June 30,
2011
  Six Months
Ended June 30,
2010
 

Cash flows from operating activities:

             

Net income (loss)

  $ (8,053 ) $ 3,988  

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:

             

Depreciation and amortization

    2,623     2,495  

Loss (gain) on disposal of long-lived assets

    65     (34 )

Changes in assets and liabilities:

             

Decrease in accounts receivable

    44,173     13,481  

Decrease in inventory

    42,696     70,689  

Change in net derivative assets / liabilities

    (5,488 )   (24,916 )

Decrease in margin deposits

    7,412     23,067  

Decrease (increase) in other assets

    (483 )   6,853  

Decrease in accounts payable

    (35,302 )   (20,546 )

Decrease in payables to pre-petition creditors

    (202 )   (10,059 )

Increase (decrease) in other liabilities

    (817 )   2,370  
           

Net cash provided by operating activities

    46,624     67,388  
           

Cash flows from investing activities:

             

Capital expenditures

    (889 )   (3,320 )

Proceeds from sale of long-lived assets

    22     687  
           

Net cash used in investing activities

    (867 )   (2,633 )
           

Cash flows from financing activities:

             

Change in book overdrafts

    (212 )   (559 )

Net distributions to SemGroup

    (45,545 )   (64,196 )
           

Net cash used in financing activities

    (45,757 )   (64,755 )
           

Net change in cash and cash equivalents

         

Cash and cash equivalents at beginning of period

         
           

Cash and cash equivalents at end of period

  $   $  
           
           

   

The accompanying notes are an integral part of these unaudited condensed financial statements.

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Notes to Unaudited Condensed Financial Statements

1. OVERVIEW

Basis of presentation

        SemStream, L.P. is a wholly owned subsidiary of SemGroup Corporation engaged in the terminalling, storage, marketing and distribution of propane and other natural gas liquids in the United States. Its operations included sales to retail, wholesale and commercial customers linked to purchases from suppliers, and encompassed three primary focus areas: (i) wholesale marketing at both private and common carrier terminals; (ii) natural gas liquids supply to retail, petrochemical and commercial customers; and (iii) residential propane supply in Arizona.

        As described in Note 6, on November 1, 2011, SemStream, L.P. contributed certain of its assets to NGL Energy Partners LP ("NGL Energy"). The contributed assets included SemStream, L.P.'s primary operating assets, excluding those of its residential operations. The accompanying financial statements of the SemStream Non-Residential Division reflect the historical activity of the operations that were contributed to NGL Energy. The SemStream Non-Residential Division will hereinafter be referred to as "SemStream".

        SemGroup Corporation is a Delaware Corporation with its headquarters in Tulsa, Oklahoma. SemGroup Corporation is the successor entity of SemGroup, L.P., which was an Oklahoma limited partnership. The term "SemGroup" refers to SemGroup Corporation, SemGroup, L.P., and their other controlled subsidiaries.

        The accompanying condensed financial statements are unaudited. The condensed balance sheet at December 31, 2010 is derived from audited financial statements.

        These unaudited condensed financial statements as of June 30, 2011 and for the six months ended June 30, 2011 and 2010 have been prepared in accordance with accounting principles generally accepted in the United States and the rules and regulations of the Securities and Exchange Commission. These unaudited condensed financial statements include all normal and recurring adjustments that, in the opinion of management, are necessary to present fairly the financial position of SemStream and the results of its operations and its cash flows. We have evaluated subsequent events for accrual or disclosure in these unaudited condensed financial statements through November 3, 2011, which is the date these financial statements were issued.

        Pursuant to the rules and regulations of the Securities and Exchange Commission, the accompanying financial statements do not include all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States. These unaudited condensed financial statements should be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 2010.

        The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures in the financial statements. Although management believes these estimates are reasonable, actual results could differ materially from these estimates. Due to the seasonal nature of SemStream's operations and other factors, the results of operations for the six months ended June 30, 2011 are not necessarily indicative of the results to be expected for the full year ending December 31, 2011.

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Notes to Unaudited Condensed Financial Statements (Continued)

1. OVERVIEW (Continued)

Operations

        SemStream's operations included the following:

Bankruptcy

        On July 22, 2008 SemGroup, L.P. and SemStream, L.P. filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. While in bankruptcy, SemGroup, L.P. filed a Plan of Reorganization with the court, which was confirmed on October 28, 2009. The Plan of Reorganization determined, among other things, how pre-Petition Date obligations would be settled, the equity structure of the reorganized company upon emergence, and the financing arrangements upon emergence. SemGroup Corporation and SemStream, L.P. emerged from bankruptcy protection on November 30, 2009 (the "Emergence Date").

2. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK

        SemStream's results of operations and cash flows are impacted by changes in market prices for petroleum products. This exposure to commodity price risk was managed, in part, by entering into various commodity derivatives.

        During 2011 and 2010, SemStream managed commodity price risk by limiting its net open positions subject to outright price risk and basis risk resulting from grade, location or time differences. SemStream did so by selling and purchasing similar quantities of natural gas liquids with purchase and sale transactions for current or future delivery, by entering into future delivery and purchase obligations with futures contracts or other commodity derivatives and employing its storage and transportation assets. At times SemStream hedged its natural gas liquids commodity price exposure with derivatives on commodities other than natural gas liquids due to the limited size of the market for natural gas liquids derivatives. In addition, physical transaction sale and purchase strategies were intended to lock in positive margins for SemStream, e.g., the sales price was sufficient to cover purchase costs, any other fixed and variable costs and SemStream's profit. All marketing activities were subject to SemGroup's risk management policy, which established limits to manage risk and mitigate financial exposure.

        During 2011 and 2010, SemStream's commodity derivatives were comprised of natural gas liquids swaps, forward contracts and futures contracts. These are defined as follows:

        Swaps—Over the counter transactions where a floating price, basis or index is exchanged for a fixed (or a different floating) price, basis, or index at a preset schedule in the future according to an agreed upon formula.

        Forward contracts—Over the counter contracts to buy or sell a commodity at an agreed upon future date. The buyer and seller agree on specific terms (price, quantity, delivery period, and location) and conditions at the inception of the contract.

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Notes to Unaudited Condensed Financial Statements (Continued)

2. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK (Continued)

        Futures contracts—Exchange traded contracts to buy or sell a commodity. These contracts are standardized by the exchange in terms of quality, quantity, delivery period and location for each commodity.

        The table below summarizes the balances of derivative assets and liabilities at June 30, 2011 and December 31, 2010 (in thousands):

 
  June 30, 2011   December 31, 2010  
 
  Level 1   Level 2   Level 3   Netting   Total   Level 1   Level 2   Level 3   Netting   Total  

Assets

  $ 14   $ 2,132   $ 7,359   $ (232 ) $ 9,273   $ 84   $ 1,785   $ 2,498   $   $ 4,367  

Liabilities

    26     3,466     9,576     (232 )   12,836     2,123     6,631     4,664         13,418  
                                           

Net liabilities at fair value

  $ (12 ) $ (1,334 ) $ (2,217 ) $   $ (3,563 ) $ (2,039 ) $ (4,846 ) $ (2,166 ) $   $ (9,051 )
                                           
                                           

        Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. SemStream's assessment of the significance of a particular input to the measurement requires judgment, and may affect the valuation of assets and liabilities and their placement within the fair value levels.

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Notes to Unaudited Condensed Financial Statements (Continued)

2. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK (Continued)

        The following table reconciles changes in the fair value of commodity derivatives classified as Level 3 in the fair value hierarchy (in thousands):

 
  Six Months
Ended
June 30, 2011
  Six Months
Ended
June 30, 2010
 

Beginning balance

  $ (2,166 ) $ (23,656 )

Transfers out of Level 3(*)

    (425 )    

Total loss (realized and unrealized) included in product revenues

    (785 )   (1,265 )

Settlements

    1,159     25,585  
           

Ending balance

  $ (2,217 ) $ 664  
           
           

Amount of total loss included in earnings for the period attributable to the change in unrealized loss relating to assets and liabilities still held at the reporting date

  $ (785 ) $ (1,265 )

(*)
SemStream's policy is to recognize transfers in and transfers out as of the beginning of the reporting period.

        The following table sets forth the notional quantities for derivative instruments entered into during the periods indicated (amounts in thousands of barrels):

 
  Six Months
Ended
June 30, 2011
  Six Months
Ended
June 30, 2010
 

Sales

    8,401     3,332  

Purchases

    8,797     2,234  

        Realized and unrealized gains (losses) from SemStream's commodity derivatives were recorded to product revenue in the following amounts (in thousands):

 
  Six Months
Ended
June 30, 2011
  Six Months
Ended
June 30, 2010
 

Commodity contracts

  $ (4,333 ) $ 8,341  

3. COMMITMENTS AND CONTINGENCIES

Bankruptcy matters

(a)
Confirmation order appeals

        Manchester Securities appeal.    On October 21, 2009, Manchester Securities Corporation, a creditor of SemGroup Holdings, L.P. (a subsidiary of SemGroup), filed an objection to the Plan of Reorganization. In the objection, Manchester argued that the Plan of Reorganization should not be confirmed because it did not provide for an alleged $50 million claim of SemGroup Holdings, L.P. against SemCrude Pipeline, L.L.C. (another subsidiary of SemGroup). On October 28, 2009, the bankruptcy court overruled the objection and entered the confirmation order approving the Plan of

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Notes to Unaudited Condensed Financial Statements (Continued)

3. COMMITMENTS AND CONTINGENCIES (Continued)

Reorganization. On November 4, 2009, Manchester filed a notice of appeal of the confirmation order. On December 4, 2009, Manchester's appeal was docketed in the United States District Court for the District of Delaware.

        SemGroup filed a motion to dismiss the appeal as equitably moot. On February 18, 2011, the District Court granted SemGroup's motion to dismiss the appeal. On March 22, 2011, Manchester filed a notice to appeal this order. While SemGroup believes that this action is without merit and is vigorously defending this matter on appeal, an adverse ruling on this action could have a material adverse impact.

        Luke Oil appeal.    On October 21, 2009, Luke Oil Company, C&S Oil/Cross Properties, Inc., Wayne Thomas Oil and Gas and William R. Earnhardt Company (collectively, "Luke Oil") filed an objection to the Plan of Reorganization "to the extent that the Plan of Reorganization may alter, impair, or otherwise adversely affect Luke Oil's legal rights or other interests." On October 28, 2009, the bankruptcy court overruled the Luke Oil objection and entered the confirmation order. On November 6, 2009, Luke Oil filed a notice of appeal. On December 23, 2009, Luke Oil's appeal was docketed in the United States District Court for the District of Delaware. SemGroup filed a motion to dismiss the appeal as equitably moot. Luke Oil has filed a motion to stay the briefing on SemGroup's motion to dismiss. On February 18, 2011, the District Court denied the stay motion and ordered the parties to complete briefing. While SemGroup believes that this action is without merit and is vigorously defending this matter on appeal, an adverse ruling on this action could have a material adverse impact.

(b)
Claims reconciliation process

        A large number of parties have made claims against SemStream for obligations alleged to have been incurred prior to the Petition Date. On September 15, 2010, the bankruptcy court entered an order estimating the contingent, unliquidated and disputed claims and authorizing distributions to holders of allowed claims. Pursuant to that order, SemGroup has begun making distributions to the claimants. SemGroup continues to attempt to settle unresolved claims.

        Pursuant to the Plan of Reorganization, SemGroup committed to settle authorized and allowed bankruptcy claims by paying a specified amount of cash, issuing a specified number of warrants, and issuing a specified number of shares of SemGroup Corporation common stock. SemGroup does not believe the resolution of the remaining outstanding claims will exceed the total amount of consideration established under the Plan of Reorganization for all claimants; instead, the resolutions of the remaining claims in some cases will impact the relative share of the established pool of common stock and warrants that certain claimants receive.

        However, under certain circumstances SemGroup could be required to pay additional funds to settle the specified group of claims to be settled with cash. Pursuant to the Plan of Reorganization, a specified amount of restricted cash was set aside at the Emergence Date, which SemGroup expects to be sufficient to settle this group of claims. Since the Emergence Date, SemGroup has made significant progress in resolving these claims, and continues to believe that the cash set aside at the Emergence Date will be sufficient to settle these claims. However, SemGroup has not yet reached a resolution of all of these claims, and if the total settlement amount of all of these claims exceeds the specified amount, SemGroup will be required to pay additional funds to satisfy the total settlement amount for

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Notes to Unaudited Condensed Financial Statements (Continued)

3. COMMITMENTS AND CONTINGENCIES (Continued)

this specified group of claims. If this were to become probable of occurring, SemGroup would be required to record a liability and a corresponding expense, and SemStream could be required to share in this expense.

Environmental

        SemStream may from time to time experience leaks of petroleum products from its facilities, as a result of which it may incur remediation obligations or property damage claims. In addition, SemStream is subject to numerous environmental regulations. Failure to comply with these regulations could result in the assessment of fines or penalties by regulatory authorities.

Asset retirement obligations

        SemStream may be subject to removal and restoration costs upon retirement of their facilities. However, SemGroup does not believe the present value of such obligations under current laws and regulations, after taking into account the estimated lives of the facilities, is material to SemStream's financial position or results of operations.

Other matters

        SemStream is party to various other claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of SemGroup's management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, will not have a material adverse effect on SemStream's financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of SemStream's liabilities may change materially as circumstances develop.

Purchase and sale commitments

        SemStream routinely entered into agreements to purchase and sell petroleum products at specified future dates. SemStream established a margin for these purchases by entering into various types of physical and financial sales and exchange transactions through which it sought to maintain a position that was substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. SemStream accounted for these commitments as normal purchases and sales, and therefore did not record assets or liabilities related to these agreements until the product was purchased or sold. At June 30, 2011, such commitments included the following (in thousands):

 
  Volume
(barrels)
  Value  

Floating price purchases

    1,722   $ 110,353  

Floating price sales

    789   $ 51,273  

        Certain of the commitments shown in the table above relate to agreements to purchase product from a counterparty and to sell a similar amount of product (in a different location) to the same counterparty. Many of the commitments shown in the table above are cancellable by either party, as long as notice is given within the time frame specified in the agreement (generally 30 to 120 days).

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Notes to Unaudited Condensed Financial Statements (Continued)

3. COMMITMENTS AND CONTINGENCIES (Continued)

        SemStream has also entered into an agreement under which it is obligated to purchase all of the propane produced by a third-party refinery at a price that floats based on market rates. Under this agreement, which expires March 31, 2012, SemStream purchased 8.8 million gallons of propane during the six months ended June 30, 2011 for a total price of $13.2 million.

        SemStream has also entered into a long term marketing agreement to market all natural gas liquids produced by a third party's natural gas processing plants. The agreement expires March 31, 2022. SemStream marketed 26.9 million gallons of natural gas liquids at a purchase cost of $41.8 million during the six months ended June 30, 2011 pursuant to this agreement.

4. NET PARENT EQUITY

        The following table shows the changes in SemStream's net parent equity from December 31, 2010 to June 30, 2011 (in thousands):

Balance at December 31, 2010

  $ 227,676  

Net loss

    (8,053 )

Net distributions to SemGroup

    (45,545 )
       

Balance at June 30, 2011

  $ 174,078  
       
       

5. TRANSACTIONS WITH SEMGROUP

Intercompany Accounts

        SemStream participated in SemGroup's cash management program. Under this program, cash SemStream received from customers was transferred to SemGroup on a regular basis; when SemStream remitted payments to suppliers, SemGroup transferred cash to SemStream to cover the payments. In addition, SemGroup incurred certain expenses on SemStream's behalf that are reported within SemStream's statements of operations.

        SemStream recorded transactions with SemGroup and its other controlled subsidiaries to intercompany accounts. When SemStream's intercompany accounts were in a net receivable position, the balance has been reported as a reduction to equity on the balance sheet. When SemStream's intercompany accounts were in a net payable position, the balance has been reported as a current liability on the balance sheet. In the statements of cash flows, SemStream has reported the net change in the intercompany accounts as a financing cash flow within "net distributions to SemGroup". SemStream has reported the net change in equity associated with these transactions as "net distributions to SemGroup" in the table in Note 4 showing the changes in net parent equity.

        SemStream's intercompany accounts were in a net receivable position of $59.1 million at June 30, 2011 and $13.5 million at December 31, 2010. SemStream has reported these balances as a reduction to equity on the balance sheet, as SemStream does not expect to collect these intercompany receivables.

Direct employee expenses

        SemStream did not directly employ any persons to manage or operate its business; these functions were performed by employees of SemGroup. SemGroup charged SemStream $4.1 million during the six months ended June 30, 2011 and $3.3 million during the six months ended June 30, 2010 for direct

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SemStream Non-Residential Division

Notes to Unaudited Condensed Financial Statements (Continued)

5. TRANSACTIONS WITH SEMGROUP (Continued)

employee costs. These expenses were recorded to operating expenses and general and administrative expenses in SemStream's statements of operations.

Allocated expenses

        SemGroup incurs expenses to provide certain indirect corporate general and administrative services to its subsidiaries. Such expenses include employee compensation costs, professional fees, and rental fees for office space, among other expenses.

        SemGroup charged SemStream $2.4 million during the six months ended June 30, 2011 and $2.9 million during the six months ended June 30, 2010 for such allocated costs. These expenses were recorded to general and administrative expenses in SemStream's statements of operations.

SemGroup credit facilities

        SemGroup was a borrower under various credit agreements during the periods included in these financial statements. SemStream, L.P., along with other subsidiaries of SemGroup, served as a subsidiary guarantor under certain of these agreements. SemGroup did not allocate this debt to its subsidiaries, and SemStream's statements of operations do not include any allocated interest expense. SemGroup did not charge SemStream interest expense on intercompany payables during the years from 2008 through 2010.

        SemStream utilized letters of credit under SemGroup's credit facilities. At June 30, 2011, SemStream had outstanding letters of credit of $46.1 million. The statements of operations include direct charges from SemGroup for letter of credit usage, which is reported within interest expense.

        Subsequent to the contribution of the SemStream assets to NGL Energy on November 1, 2011, these assets no longer serve as collateral under SemGroup's credit agreements.

Product purchases and sales

        SemStream routinely entered into purchase and sale transactions with other controlled subsidiaries of SemGroup, including the following:

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SemStream Non-Residential Division

Notes to Unaudited Condensed Financial Statements (Continued)

5. TRANSACTIONS WITH SEMGROUP (Continued)

        The following table summarizes these transactions (amounts in thousands):

 
  Six Months
Ended
June 30, 2011
  Six Months
Ended
June 30, 2010
 

Revenues from SemCrude, L.P.(*)

  $ 29,523   $ 15,350  

Revenues from SemCanada Crude Company

  $   $ 9,350  

Revenues from SemStream, L.P. residential division

  $ 6,071   $ 4,267  

Purchases from SemGas, L.P. 

  $ 15,313   $ 10,898  

(*)
Certain of the purchases from SemCrude, L.P. were fixed-price forward purchases, which were recorded at fair value at each balance sheet date. The revenue amounts in this table include any unrealized gains and losses on these contracts.

6. CONTRIBUTION OF ASSETS AND LIABILITIES TO NGL ENERGY

        On November 1, 2011, SemStream, L.P. contributed many of the assets of the SemStream Non-Residential Division to NGL Energy, including the majority of the inventory, derivative assets, other current assets, property, plant and equipment, goodwill, other intangible assets, and other noncurrent assets. As part of this transaction, SemStream, L.P. also contributed certain of the liabilities of the SemStream Non-Residential Division to NGL Energy, including the derivative liabilities and capital leases. In return for this contribution, SemStream received $93 million of cash from NGL Energy (subject to post-closing adjustments), 8,932,031 common units representing limited partner interests in NGL Energy, and a 7.5% interest in the general partner of NGL Energy. Also as part of this transaction, SemStream agreed to waive its distribution rights on certain of the common units for a specified period of time.

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REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

To the Partners of
NGL Energy Partners LP:

        We have audited the accompanying combined balance sheets of the Businesses of Osterman Associated Companies Contributed to NGL Energy Partners LP (taken as a whole the "Company") as of September 30, 2011 and 2010 and the related combined statements of operations and changes in equity of the combined companies and cash flows for the years ended September 30, 2011, 2010 and 2009. These combined financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these combined financial statements based on our audit.

        We conducted our audits in accordance with auditing standards generally accepted in the United States of America established by the American Institute of Certified Public Accountants. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the combined financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the combined financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the combined financial statements referred to above present fairly, in all material aspects, the combined financial position of the Businesses of Osterman Associated Companies Contributed to NGL Energy Partners LP as of September 30, 2011 and 2010 and the combined results of their operations and their cash flows for the years ended September 30, 2011, 2010 and 2009 in conformity with accounting principles generally accepted in the United States of America.

/s/ Graham Shepherd, PC
Worcester, Massachusetts
November 14, 2012

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Combined Balance Sheets

September 30, 2011 and 2010

(U.S. Dollars in Thousands)

 
  2011   2010  

ASSETS

             

CURRENT ASSETS:

             

Cash and cash equivalents

  $ 21,908   $ 13,416  

Accounts receivable, net of allowance for doubtful accounts of $650 and $550, respectively

    6,295     5,305  

Accounts receivable from stockholders and other related parties

    5,931     4,064  

Inventories

    3,771     2,824  

Prepaid expenses

    1,045     1,324  

Deferred income taxes

    266     80  

Other current assets

    101     101  
           

Total current assets

    39,317     27,114  

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $41,899 and $38,517, respectively

   
17,635
   
18,729
 

GOODWILL

    380     380  

INTANGIBLE ASSETS, net of accumulated amortization of $3,045 and $2,616, respectively

    3,436     3,865  

OTHER NON-CURRENT ASSETS

    233     235  
           

Total assets

  $ 61,001   $ 50,323  
           
           

LIABILITIES AND NET EQUITY OF COMBINED COMPANIES

             

CURRENT LIABILITIES:

             

Trade accounts payable

  $ 2,615   $ 3,258  

Income taxes payable

    542     301  

Accrued expenses and other payables

    1,897     1,398  

Customer deposits

    4,033     3,701  

Current maturities of long-term debt

        385  

Due to stockholders

    6     5  
           

Total current liabilities

    9,093     9,048  

LONG-TERM LIABILITIES:

   
 
   
 
 

Long-term debt, net of current maturities

        2,312  

Payable to related parties

    755     681  

Deferred income taxes

    592     414  

COMMITMENTS AND CONTINGENCIES

   
 
   
 
 

NET EQUITY OF COMBINED COMPANIES

   
50,561
   
37,868
 
           

Total liabilities and net equity of combined companies

  $ 61,001   $ 50,323  
           
           

   

The accompanying notes are an integral part of these combined financial statements.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Combined Statements of Operations and Changes in Equity of Combined Companies

For the Years Ended September 30, 2011, 2010 and 2009

(U.S. Dollars in Thousands)

 
  2011   2010   2009  

REVENUES:

                   

Propane sales

  $ 105,592   $ 87,678   $ 82,877  

Sales of parts and appliances

    5,385     2,924     3,098  

Other operating revenues

    1,041     1,108     909  
               

Total Revenues

    112,018     91,710     86,884  

COST OF SALES

   
69,753
   
52,993
   
43,792
 
               

Gross Margin

    42,265     38,717     43,092  

OPERATING COSTS AND EXPENSES:

   
 
   
 
   
 
 

Operating and general and administrative

    23,341     21,801     22,368  

Depreciation and amortization

    3,811     3,871     3,687  
               

Operating Income

    15,113     13,045     17,037  

OTHER INCOME (EXPENSE):

   
 
   
 
   
 
 

Interest expense

    (62 )   (211 )   (341 )

Interest income

    231     114     191  

Other, net

    1,334     38     211  
               

INCOME BEFORE INCOME TAXES

    16,616     12,986     17,098  

PROVISION FOR INCOME TAXES

   
563
   
733
   
736
 
               

Net Income

  $ 16,053   $ 12,253   $ 16,362  

Net equity of combined companies, beginning of period

   
37,868
   
30,042
   
19,077
 

Contributions

    579     1,387     97  

Distributions

    (3,939 )   (5,814 )   (5,494 )
               

Net equity of combined companies, end of period

  $ 50,561   $ 37,868   $ 30,042  
               
               

   

The accompanying notes are an integral part of these combined financial statements.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Combined Statements of Cash Flows

For the Years Ended September 30, 2011, 2010 and 2009

(U.S. Dollars in Thousands)

 
  2011   2010   2009  

OPERATING ACTIVITIES:

                   

Net income

  $ 16,053   $ 12,253   $ 16,362  

Adjustments to reconcile net income to net cash provided by operating activities:

                   

Depreciation and amortization

    3,811     3,871     3,687  

Deferred income tax (benefit) provision

    (8 )   75     (22 )

(Gain) loss on sale of assets

    (1,141 )       (119 )

Changes in operating assets and liabilities—

                   

Accounts receivable

    (990 )   (863 )   2,475  

Inventories

    (947 )   (663 )   1,390  

Prepaid expenses and other current assets

    279     (707 )   (51 )

Accounts payable

    (643 )   422     (1,496 )

Accrued expenses and other payables

    499     (14 )   254  

Income taxes payable

    241     (399 )   549  

Customer deposits

    332     503     (1,327 )
               

Net cash provided by operating activities

    17,486     14,478     21,702  
               

INVESTING ACTIVITIES :

                   

Purchases of long-lived assets

    (2,537 )   (3,841 )   (6,542 )

Proceeds from sales of assets

    1,390         164  

Net (advances to) repayments from related parties

    2     (35 )    

Other

            (100 )
               

Net cash used in investing activities

    (1,145 )   (3,876 )   (6,478 )
               

FINANCING ACTIVITIES:

                   

Proceeds from long-term debt

            1,978  

Payments on long-term debt

    (2,697 )   (2,166 )   (2,164 )

Net (advances to) repayments from stockholders and related parties

    (1,792 )   (6,567 )   1,756  

Contributions from stockholders

    579     1,387     97  

Distributions

    (3,939 )   (5,814 )   (5,494 )
               

Net cash used in financing activities

    (7,849 )   (13,160 )   (3,827 )
               

Net change in cash and cash equivalents

    8,492     (2,558 )   11,397  

Cash and cash equivalents, beginning of period

    13,416     15,974     4,577  
               

Cash and cash equivalents, end of period

  $ 21,908   $ 13,416   $ 15,974  
               
               

   

The accompanying notes are an integral part of these combined financial statements.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements

For the Years Ended September 30, 2011, 2010 and 2009

Note 1—Nature of Operations and Organization

        The accompanying combined financial statements represent the financial statements of the Osterman Associated Companies (collectively, "the Company"), consisting of the following individual entities which are related through common control and ownership:

        The Company operates primarily in the retail propane business throughout New England and New York.

        On October 3, 2011, the Company closed an agreement to contribute substantially all of its assets to NGL Energy Partners LP ("NGL Energy") in exchange for $96.0 million and 4 million common units of NGL Energy (see Note 14). The agreement contemplated a post-closing working capital payment of $4.8 million for certain working capital items.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 2—Summary of Significant Accounting Policies

Basis of Presentation

        The accompanying combined financial statements are prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All significant intercompany transactions have been eliminated in preparing these combined financial statements.

Estimates

        The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management's knowledge of current events, historical experience and various other assumptions that they believe to be reasonable under the circumstances.

        Critical estimates made in the preparation of these combined financial statements include the collectability of accounts receivable; the recoverability of inventories; useful lives and recoverability of property, plant and equipment and amortized intangible assets; the impairment of goodwill; accruals for various commitments and contingencies; allocations of corporate level expenses; and provision for income taxes, among others. Although management believes these estimates are reasonable, actual results could differ from the estimates.

Fair Value Measurements

        The Company applies fair value measurements to certain assets and liabilities, principally assets and liabilities acquired in a business combination. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value should be based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of the Company's own nonperformance risk on its liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid).

        Management uses the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 2—Summary of Significant Accounting Policies (Continued)

        The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

Revenue Recognition

        The Company's revenue is primarily generated by the sale of propane, propane-related appliances, parts and fittings, rental of equipment and by services provided to its customers in the northeastern United States.

        The Company accrues revenues from propane and propane-related sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser or installation of the appliance. The Company records service revenues at the time the service is performed and tank and other rentals over the term of the lease. The Company records product purchases at the time title to the product transfers to the Company, which typically occurs upon receipt of the product. Revenue-related taxes collected from customers and remitted to taxing authorities, principally sales and use taxes, are presented on a net basis.

Cost of Sales

        "Cost of Sales" includes all costs incurred to acquire propane, including the costs of purchasing, terminalling, and storing inventory prior to delivery to the customer, as well as any costs related to the sale of propane appliances and equipment. Cost of sales does not include any depreciation or amortization of property, plant and equipment or intangible assets. Depreciation and amortization is separately classified in the combined statements of operations.

Operating and General and Administrative Expenses

        "Operating and General and Administrative Expenses" include costs of personnel, vehicles, delivery, handling, plants, district offices, selling, marketing, credit and collections and other functions related to the retail distribution of propane and related equipment and supplies and the direct and allocated expenses of personnel, executives, corporate office locations and other functions related to centralized corporate and overhead activities.

Advertising Costs

        The Company expenses advertising costs as incurred. The total advertising expense for the years ended September 30, 2011, 2010 and 2009 was approximately $367,000, $437,000 and $375,000, respectively.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 2—Summary of Significant Accounting Policies (Continued)

Cash and Cash Equivalents

        The Company considers all highly liquid investments with a maturity of three months or less at acquisition date as cash equivalents.

        In the ordinary course of business, the Company has, at various times, cash deposits with a bank which are in excess of federally insured limits. Management believes that the possibility of any loss is minimal.

        Supplemental cash flow information:

 
  2011   2010   2009  
 
  (in thousands)
 

Interest paid

  $ 62   $ 107   $ 184  
               
               

Income taxes paid

  $ 148   $ 1,742   $ 248  
               
               

Accounts Receivable and Concentration of Credit Risk

        The Company grants credit to customers for the purchase of propane and propane-related products. Accounts receivable are uncollateralized customer obligations due under normal trade terms. Accounts receivable are stated at the amount billed to the customer plus any accrued and unpaid interest on unpaid and past due accounts receivable. Interest charges during the periods presented were not material.

        The carrying amount of accounts receivable is reduced by a valuation allowance that reflects management's best estimate of the uncollectible amounts. Management individually reviews past due accounts receivable balances and provides a specific reserve based on an assessment of current customer creditworthiness. Management also provides a general allowance amount for accounts not currently delinquent.

        Changes in the allowance for doubtful accounts during the periods indicated are as follows:

 
  2011   2010   2009  
 
  (in thousands)
 

Allowance for doubtful accounts, beginning of period

  $ 550   $ 500   $ 500  

Bad debt provision

    755     274     596  

Write off of uncollectible accounts, net of recoveries

    (655 )   (224 )   (596 )
               

Allowance for doubtful accounts, end of period

  $ 650   $ 550   $ 500  
               
               

        For the years ended September 30, 2011, 2010 and 2009, no individual customer accounted for more than 10% of the Company's combined revenues.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 2—Summary of Significant Accounting Policies (Continued)

Accounts Receivable From (Due to) Stockholders and Other Related Parties

        The current receivables from (due to) the Company's stockholders and other related parties are unsecured and have no stated repayment terms but are due on demand.

Inventories

        The Company's inventories consist primarily of propane, valued at cost determined using the average cost method. Cost includes the cost of transportation and storage. Parts and supplies inventories are carried at the lower of cost or market, with cost determined using the average cost method.

        Inventories consisted of the following:

 
  2011   2010  
 
  (in thousands)
 

Propane

  $ 2,966   $ 2,024  

Parts, appliances and other

    805     800  
           

Total

  $ 3,771   $ 2,824  
           
           

Property, Plant and Equipment, Depreciation and Impairments

        Property, plant and equipment are stated at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and maintenance and repairs are expensed as incurred. When the Company disposes of assets, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in other income. Depreciation expense is computed primarily using the straight-line method over the useful lives (see Note 5).

        The Company evaluates the carrying value of its long-lived assets for potential impairment when events and circumstances warrant such a review. A long-lived asset is considered impaired when the anticipated undiscounted future cash flows from a logical grouping of assets is less than its carrying value. In that event, a loss is recognized equal to the amount by which the carrying value exceeds the fair value of the assets. No impairments of long-lived assets were recorded for the years ended September 30, 2011, 2010 and 2009.

Intangible Assets

        The Company's identifiable intangible assets consist primarily of customer lists and covenants not to compete acquired in business combinations. The Company capitalizes acquired intangible assets if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of an intent to do so.

        Intangible assets with estimable useful lives are amortized over their respective useful lives on a straight-line basis to their estimated residual values, and reviewed for impairment annually (see Note 6).

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 2—Summary of Significant Accounting Policies (Continued)

Goodwill

        Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Changes to recorded goodwill during the three year period ended September 30, 2011 were as follows:

 
  2011   2010   2009  
 
  (in thousands)
 

Balance, beginning of period

  $ 380   $ 380   $ 300  

Acquisitions of retail propane businesses

            80  
               

Balance, end of period

  $ 380   $ 380   $ 380  
               
               

        The Company evaluates goodwill for impairment annually or when events or circumstances occur indicating that goodwill might be impaired. The Company performs this impairment testing at year end.

        The annual impairment assessment of goodwill is a two-step process:

        The Company utilizes the market approach in determining the fair value of the reporting unit. The market approach considers forecasted discounted future cash flows and a terminal value which applies a market multiple to adjusted cash flows. Based upon this analysis, the Company concluded that the fair value of the reporting unit exceeded its carrying value and therefore step 2 of goodwill impairment testing was not required for any of the periods presented.

        Estimates and assumptions used to perform the impairment testing are inherently uncertain and can significantly affect the outcome of the impairment test. The estimates and assumptions the Company used in the annual assessment for impairment of goodwill included market participant considerations and future forecasted operating results. Changes in operating results and other assumptions could materially affect these estimates.

Asset Retirement Obligations

        The Company records the fair value of an asset retirement obligation as a liability in the period a legal obligation for the retirement of tangible long-lived assets is incurred, typically at the time the assets are placed into service if the Company can reasonably estimate such retirement obligations. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 2—Summary of Significant Accounting Policies (Continued)

measurement, the Company also recognizes changes in the amount of the liability resulting from the passage of time and revisions to either the timing or amount of estimated cash flows.

        The Company has determined that it is obligated by contractual requirements to remove facilities or perform other remediation upon retirement of certain assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates. However, the Company is not able to reasonably measure the fair value of the asset retirement obligations as of September 30, 2011, 2010 or 2009 because the settlement dates were indeterminable. An asset retirement obligation will be recorded in the periods the Company can reasonably determine the settlement dates.

Income Taxes

        Certain of the companies included in these combined financial statements are S corporations or limited liability companies whose earnings or losses for federal and state income tax purposes are included in the tax returns of the individual owners. For those entities, net earnings for financial statement purposes may differ significantly from taxable income reportable to such owners as a result of differences between the tax basis and financial reporting basis of assets and liabilities. The Company pays income taxes to certain states as required by the tax code of the respective states.

        Those combined companies which are taxable ("C") corporations follow the asset and liability method of accounting for income taxes, under which deferred income taxes are recorded based upon differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets are received and liabilities settled (see Note 8).

        On October 1, 2009 the Company adopted the provision for the accounting for uncertainty in income tax positions. The Company is required to recognize in its financial statements the impact of the tax position if it is more likely than not the position will not be sustained on audit based on the technical merits of the position.

        The Company files federal, Massachusetts, Connecticut, Rhode Island, New Hampshire, New York, Maine and Vermont income tax returns. The income tax returns for tax years 2009 and beyond remain subject to examination by the Internal Revenue Service and the Department of Revenue for all states in which the Company files.

        The Company did not have unrecognized tax benefits as of September 30, 2011 and does not expect this to change significantly over the next 12 months. The Company will recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense.

Customer Deposits

        The Company records customer advances and deposits on product purchases as a liability in the combined balance sheets.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 3—Recent Accounting Standards

        In September 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2011-08. Intangibles—Goodwill and Other (Topic 350): Testing Goodwill for Impairment ("ASU 2011-08"), which simplifies how entities test goodwill for impairment. ASU 2011-08 gives entities the option, under certain circumstances, to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. ASU 2011-08 is effective for fiscal years beginning after December 15, 2011, and early adoption is permitted. The Company does not expect that the adoption of this standard will materially impact its financial position or results of operations.

        During 2009, the Company adopted the updated GAAP rules for subsequent events. Under this update, management is required to evaluate subsequent events through the date that the combined financial statements are available to be issued and to disclose the date through which subsequent events are evaluated. The adoption of this standard does not change the Company's practices with respect to evaluating, recording, and disclosing subsequent events; therefore, adoption of this update had no impact on the Company's combined balance sheets or statements of results of operations.

Note 4—Acquisitions of Businesses

        On October 6, 2008 the Company entered into an agreement to purchase the assets of Wesco Propane, Inc. as detailed below. The acquisition was accomplished through the use of the Company's line of credit and internally generated funds.

        On September 1, 2009, the Company entered into an agreement to purchase the assets of Mack Bros., Inc. located in Readsboro, Vermont, as detailed below. The acquisition was accomplished through the use of internally generated funds.

        The fair values of the assets acquired in these acquisitions are as follows (in thousands):

 
  2009  
 
  Wesco   Mack Bros.  
 
  (in thousands)
 

Accounts receivable

  $ 52   $  

Inventory

        5  

Tanks and other equipment

    450     190  

Transportation equipment

    85     30  

Computer and office equipment

    20     2  

Customer lists

    1,560     83  

Non-compete agreement

        200  

Goodwill

        80  
           

  $ 2,167   $ 590  
           
           

        The Company included the results of operations in its financial statements beginning on the acquisition closing date. The pro forma impact of these acquisitions is not presented as such impact is not material.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 5—Property, Plant and Equipment

        Property, plant and equipment consist of the following:

 
  Estimated Useful
Lives (Years)
  2011   2010  
 
   
  (in thousands)
 

Retail propane equipment and tanks

  5 - 20   $ 37,200   $ 35,752  

Vehicles

  5 - 7     14,845     14,322  

Buildings and improvements

  15 - 40     4,614     4,047  

Land

  N/A     2,216     2,466  

Other

  5 - 7     659     659  
               

        59,534     57,246  

Less: Accumulated depreciation

        41,899     38,517  
               

Net property, plant and equipment

      $ 17,635   $ 18,729  
               
               

        Depreciation expense was as follows for the periods indicated:

2011   2010   2009  
(in thousands)
 
$ 3,382   $ 3,442   $ 3,298  

Note 6—Intangible Assets

        Intangible assets (all amortizable) consist of the following:

 
  Estimated Useful
Lives (Years)
  2011   2010  
 
   
  (in thousands)
 

Customer lists

  15   $ 6,313   $ 6,313  

Non-compete agreements

  5     168     168  
               

Total intangible assets

        6,481     6,481  

Less: Accumulated amortization

        3,045     2,616  
               

Net intangible assets

      $ 3,436   $ 3,865  
               
               

        Amortization expense was approximately $429,000, $429,000 and $389,000 for the years ended September 30, 2011, 2010 and 2009, respectively.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 6—Intangible Assets (Continued)

        Future amortization expense is estimated as follows (in thousands):

2012

  $ 429  

2013

    429  

2014

    414  

2015

    370  

2016

    349  

Thereafter

    1,445  
       

  $ 3,436  
       
       

Note 7—Long-Term Debt

        The Company's long-term debt consists of the following:

 
  2011   2010  
 
  (in thousands)
 

Line of credit agreement with bank

  $   $ 2,697  

Revolving credit facility with bank

         
           

        2,697  

Less—current maturities

        385  
           

Long-term debt

  $   $ 2,312  
           
           

        The line of credit agreement provides that the Company may borrow on a revolving basis until April 30, 2012 up to $11 million for acquisitions and asset purchases based upon an annual calculation. Interest is payable monthly in arrears. The Company has agreed to pay minimally the outstanding principal as of August 1st in each year in monthly installments equal to 1/84th of the outstanding principal balance. At September 30, 2011 and 2010 the monthly principal payments due were approximately $0 and $32,000, respectively. The Company has the right to select an interest rate based on the Bank's Prime Rate or the LIBOR 1-month index rate plus 190 basis points. In addition, an Unused Facility Fee of 0.25% per annum is charged quarterly on the average daily-undisbursed amount of the line of credit. The line of credit contains certain loan covenants and the Company was in compliance with all loan covenants at September 30, 2011 and 2010. The interest rates at September 16, 2011 and September 30, 2010 were 2.08% and 2.16%, respectively.

        Long-term debt is secured by substantially all of the assets of the Company with recourse limited to real estate. The total borrowings of the revolving note agreement and the line of credit agreement may not exceed $18 million in the aggregate. The line of credit was paid in full on August 17, 2011 and terminated on September 16, 2011.

        In addition, the Company has long-term debt payable to a related party of $755,000 and $681,000 at September 30, 2011 and 2010, respectively. This consists primarily of loans for which there are no established payment terms and which the Company believes will not require payment during the next 12 months.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 8—Income Taxes

        The Company's provision for income taxes consists of the following:

 
  2011   2010   2009  
 
  (in thousands)
 

Current:

                   

Federal

  $ 20   $ 8   $ 75  

State

    551     650     682  

Deferred:

                   

Federal

    (17 )   49     (56 )

State

    9     26     35  
               

  $ 563   $ 733   $ 736  
               
               

        The Company's effective income tax rate differs from the Federal statutory rate of 35% due to the taxable income of the tax pass through entities (S corporations, limited partnerships and limited liability companies) and the effect of state income taxes.

        The Company's Subchapter S corporations pay a portion of state corporate income tax to certain states as dictated by the tax code of the respective states. The aggregate amount of state corporate income tax expense based on these calculations is approximately $551,000, $633,000 and $667,000 for the years ended September 30, 2011, 2010 and 2009 respectively.

        Net deferred tax liabilities represent the tax effects of taxable and deductible temporary differences between financial and income tax reporting. The taxable temporary differences consist primarily of net property and equipment values, net intangible asset values and net operating losses.

        The net deferred tax liability consists of the following:

 
  2011   2010  
 
  (in thousands)
 

Deferred tax assets related to:

             

Accounts receivable

             

State

  $ 29     25  

Net operating loss carryovers

             

Federal

    234     270  

State

    3     2  

Deferred state tax

             

Federal

    25     30  

Deferred tax liabilities related to:

   
 
   
 
 

Property and equipment, net

             

Federal

    (134 )   (178 )

State

    (290 )   (272 )

Intangible assets, net

             

Federal

    (151 )   (165 )

State

    (42 )   (46 )
           

Net liability

  $ (326 ) $ (334 )
           
           

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 8—Income Taxes (Continued)

        The amounts are presented in the Company's combined balance sheets as follows:

 
  2011   2010  
 
  (in thousands)
 

Deferred tax assets—current

             

Federal

  $ 234   $ 54  

State

    32     26  
           

  $ 266   $ 80  
           
           

Deferred tax liabilities—non-current

             

Federal

  $ 260   $ 97  

State

    332     317  
           

  $ 592   $ 414  
           
           

Note 9—Commitments and Contingencies

Environmental Matters

        The Company's operations are subject to extensive Federal, state and local environmental laws and regulations that could require expenditures for remediation of operating facilities. Although management believes the Company's operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the propane distribution, terminal and storage business, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations or prior operations, could result in substantial costs and liabilities. Accordingly, the Company has adopted policies, practices and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financial liability which could result from such events. However, some risk of environmental or other damage is inherent in the Company's business.

Litigation

        The Company is involved in claims and legal actions arising in the ordinary course of business. Management believes that the ultimate disposition of these matters will not have a material adverse effect on the Company's financial position and results of operations.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 10—Net Equity of Combined Companies

        Net equity of the combined companies on the combined balance sheets includes the common stock of the combined entities. The legal capital of each such entity is as follows at September 30, 2011 and 2010:

 
  Par or Stated
Value
 
 
  (in thousands)
 

E. Osterman Gas Service, Inc.

       

Common stock, no par value, 100 shares authorized, issued and outstanding. 

  $ 1  

Milford Propane, Inc.

   
 
 

Common stock, no par value, 100 shares authorized, issued and outstanding. 

    4  

Saveway Propane Gas Service, Inc.

   
 
 

Common stock, no par value, 5,000 shares authorized, issued and outstanding. 

    2  

E Osterman, Inc.

   
 
 

Common stock, no par value, 100 shares voting and 900 shares nonvoting authorized, issued and outstanding. 

    1  

Osterman Propane, Inc.

   
 
 

Common stock, no par value, 5,000 shares authorized, 100 shares issued and outstanding. 

    1  

A O Energy, Inc.

   
 
 

Common stock, no par value, 200,000 shares authorized, 100 shares issued and outstanding. 

    10  

Osterman Propane Storage, Inc.

   
 
 

Common stock, no par value, 200,000 shares authorized, 1,000 shares issued and outstanding. 

    1  

Osterman Associated Companies, Inc.

   
 
 

Common stock, no par value, 1,000 shares authorized, 100 shares issued and outstanding. 

     

Propane Gas, Inc.

   
 
 

Common stock, no par value, 20,000 shares authorized, 12,000 shares issued and outstanding. 

     

E Osterman Propane, Inc.

   
 
 

Common stock, no par value, 100 shares authorized, issued and outstanding. 

     
       

Total common stock

  $ 20  
       
       

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 11—Fair Value of Financial Instruments

        For cash and cash equivalents, accounts receivable, accounts payable, accrued expenses and other payables, the carrying value is a reasonable estimate of fair value, primarily because of the short-term nature of the instruments (considered to be Level 1). The Company has no assets or liabilities that are required to be recorded on the basis of fair value at September 30, 2011 or 2010.

Note 12—Employee Benefits

        The Company has a qualified deferred compensation plan, 401(k) and profit sharing plan, which covers substantially all employees who are at least twenty-one years of age and have completed three months of service. The plan is administered by an independent third party. The Company provides profit sharing at 3.0% of employees' salaries and matches 50% of employee contributions up to a maximum of 6% of participants' compensation. These benefits may be altered at the discretion of the Board of Directors. The Company's contributions to the plan were approximately $430,000, $484,000, and $430,000 for the years ended September 30, 2011, 2010 and 2009, respectively.

Note 13—Concentration of Suppliers

        The Company purchased propane from multiple suppliers. The four major suppliers collectively represented the following total percentage of purchases for the indicated periods.

2011   2010   2009  
  86 %   76 %   80 %

        Management does not believe that this represents a significant concentration risk in that, if necessary, purchases could be made from other suppliers at comparable terms.

Note 14—Subsequent Events

        Management has evaluated subsequent events through November 14, 2012, the date the combined financial statements were available to be issued.

        As discussed in Note 1, on October 3, 2011 the Company concluded an agreement to contribute substantially all of the Company's assets to NGL Energy. Associated with this contribution, the Company has reorganized to consolidate the remaining assets and those liabilities not assumed by NGL Energy consisting primarily of all receivables and payables with stockholders and other related parties and all income tax assets and liabilities.

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INDEPENDENT AUDITORS' REPORT

Members and Stockholders
Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC,
Blackhawk Gathering, Toro Operating Company, Inc., and
Striker Oilfield Services, LLC
Austin, Texas

        We have audited the accompanying combined balance sheets of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, Toro Operating Company, Inc., and Striker Oilfield Services, LLC (the "Companies") as of December 31, 2011 and 2010, and the related combined statements of income, changes in members' and stockholders' equity, and cash flows for each of the three years ended December 31, 2011, 2010, and 2009. These combined financial statements are the responsibility of the Companies' management. Our responsibility is to express an opinion on these combined financial statements based on our audits.

        We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the combined financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Companies' internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the combined financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall combined financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, Toro Operating Company, Inc., and Striker Oilfield Services, LLC at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years ended December 31, 2011, 2010, and 2009, in conformity with accounting principles generally accepted in the United States of America.

/s/ EKS&H, LLLP

January 14, 2013
Denver, Colorado

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Combined Balance Sheets

 
  December 31,  
 
  2011   2010  

Assets

       

Current assets

   
 
   
 
 

Cash and cash equivalents

  $ 9,906,016   $ 1,042,956  

Accounts receivable

    51,860,802     30,210,911  

Inventory

    1,348,826     799,619  

Due from related parties

    85,805     38,296  

Prepaid expenses and other current assets

    401,727     104,919  
           

Total current assets

    63,603,176     32,196,701  
           

Non-current assets

             

Property, plant, and equipment, net of accumulated depreciation of $4,908,488 and $2,807,540 at December 31, 2011 and 2010, respectively

    16,083,842     4,361,964  

Land

    230,253     277,656  

Deposits—related party

    250,000     250,000  

Deposits

    9,434     5,329  
           

Total non-current assets

    16,573,529     4,894,949  
           

Total assets

  $ 80,176,705   $ 37,091,650  
           
           

Liabilities and Members' and Stockholders' Equity

       

Current liabilities

   
 
   
 
 

Line-of-credit

  $ 6,000,000   $ 3,200,091  

Accounts payable—crude oil purchases

    32,974,766     15,953,689  

Accounts payable

    832,660     1,373,986  

Accrued expenses

    2,895,742     1,049,605  

Due to related parties

    12,000     30,348  

Notes payable—current portion

    4,861,915     1,246,460  

Distributions payable

    2,008,113      
           

Total current liabilities

    49,585,196     22,854,179  
           

Non-current liabilities

             

Notes payable, less current portion

    7,563,434     1,188,161  
           

Total liabilities

    57,148,630     24,042,340  
           

Commitments and contingencies (Note 7)

             

Members' and stockholders' equity

             

Common stock, 30,000 shares authorized, 15,594 shares outstanding, par value $0.10

    1,559     1,559  

Additional paid-in capital

    582,822     582,822  

Retained earnings (accumulated deficit)

    82,037     (76,155 )

Note receivable—member

    (73,609 )   (140,156 )

Members' equity

    22,435,266     12,681,240  
           

Total members' and stockholders' equity

    23,028,075     13,049,310  
           

Total liabilities and members' and stockholders' equity

  $ 80,176,705   $ 37,091,650  
           
           

   

See notes to combined financial statements.

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Table of Contents


PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Combined Statements of Income

 
  Year Ended December 31,  
 
  2011   2010   2009  

Revenue

                   

Crude oil sales

  $ 483,106,890   $ 269,442,521   $ 152,515,550  

Crude oil hauling

    14,834,234     263,911      
               

Total revenue

    497,941,124     269,706,432     152,515,550  
               

Product expenses

    471,703,255     257,064,193     143,344,684  
               

Operating expenses

                   

Transportation expenses

    3,308,633     2,157,004     1,548,502  

Personnel expenses

    4,173,651     2,749,365     2,438,043  

Equipment and facilities' expenses

    1,144,538     620,648     579,830  

General and administrative expenses

    1,866,536     1,155,757     1,361,973  

Depreciation

    2,100,948     931,547     807,415  
               

Total operating expenses

    12,594,306     7,614,321     6,735,763  
               

Other (expense) income

                   

Interest expense

    (643,300 )   (386,487 )   (325,505 )

Interest income

    2,195     7,670     7,862  

Gain on sale of assets

        149,981     73,223  
               

Total other expense, net

    (641,105 )   (228,836 )   (244,420 )
               

Net income

  $ 13,002,458   $ 4,799,082   $ 2,190,683  
               
               

   

See notes to combined financial statements.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Combined Statement of Changes in Members' and Stockholders' Equity

Years Ended December 31, 2011, 2010 and 2009

 
   
   
   
   
  Pecos Gathering and
Marketing, LLC,
Transwest Leasing, LLC,
Blackhawk
Gathering, LLC, and
Striker Oilfield
Services, LLC
   
 
 
  Toro Operating, Inc.    
 
 
  Common Stock    
   
 
 
  Retained
Earnings
(Accumulated
Deficit)
  Total Members'
and
Stockholders'
Equity
 
 
  Shares   Par Value   Additional
Paid-In Capital
  Note
Receivable
Member
  Members'
Equity
 

Balance—December 31, 2008

    15,594   $ 1,559   $ 582,822   $ (115,399 ) $   $ 7,595,733   $ 8,064,715  

Distributions

                        (1,027,000 )   (1,027,000 )

Net income

                79,386         2,111,297     2,190,683  
                               

Balance—December 31, 2009

    15,594     1,559     582,822     (36,013 )       8,680,030     9,228,398  

Note receivable—Member

                    (140,156 )       (140,156 )

Contributions

                        250,000     250,000  

Distributions

                (30,000 )       (1,058,014 )   (1,088,014 )

Net (loss) income

                (10,142 )       4,809,224     4,799,082  
                               

Balance—December 31, 2010

    15,594     1,559     582,822     (76,155 )   (140,156 )   12,681,240     13,049,310  

Payment on note receivable from member

                    66,547         66,547  

Distributions

                        (3,090,240 )   (3,090,240 )

Net income

                158,192         12,844,266     13,002,458  
                               

Balance—December 31, 2011

    15,594   $ 1,559   $ 582,822   $ 82,037   $ (73,609 ) $ 22,435,266   $ 23,028,075  
                               
                               

   

See notes to combined financial statements.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Combined Statements of Cash Flows

 
  For the Years Ended December 31,  
 
  2011   2010   2009  

Cash flows from operating activities

                   

Net income

  $ 13,002,458   $ 4,799,082   $ 2,190,683  
               

Adjustments to reconcile net income to net cash provided by operating activities

                   

Depreciation

    2,100,948     931,547     807,415  

Gain on sale of assets

        (149,981 )   (73,223 )

Loss (gain) on derivatives

    127,450     (51,409 )   18,885  

Changes in operating assets and liabilities

                   

Accounts receivable

    (21,520,215 )   (11,790,199 )   (10,261,006 )

Inventory

    (549,207 )   (204,640 )   (392,474 )

Due to/from related parties, net

    (65,857 )   (3,719 )   36,703  

Prepaid expenses and other current assets

    (300,914 )   (36,916 )   1,013,578  

Accounts payable—crude oil purchases

    17,021,077     6,884,931     6,714,113  

Accounts payable

    (541,326 )   139,813     984,586  

Accrued expenses

    1,846,137     535,847     131,694  

Deferred revenue

            (75,530 )
               

    (1,881,907 )   (3,744,726 )   (1,095,259 )
               

Net cash provided by operating activities

    11,120,551     1,054,356     1,095,424  
               

Cash flows from investing activities

                   

Purchase of land, property, plant, and equipment

    (1,043,832 )   (197,454 )   (166,957 )

Proceeds from disposal of assets

        299,962     146,446  

Cash flows from derivatives

    (257,126 )   (174,875 )   (42,000 )
               

Net cash used in investing activities

    (1,300,958 )   (72,367 )   (62,511 )
               

Cash flows from financing activities

                   

Borrowings from line-of-credit

    142,720,000     149,466,624     85,553,897  

Payments on line-of-credit

    (139,920,091 )   (147,630,430 )   (84,890,000 )

Payments on notes payable

    (2,740,863 )   (1,066,995 )   (1,311,747 )

Net advance on note receivable—member

        (200,000 )    

Member contributions

        250,000      

Member distributions

    (1,015,579 )   (1,028,170 )   (1,027,000 )
               

Net cash used in financing activities

    (956,533 )   (208,971 )   (1,674,850 )
               

Net increase (decrease) in cash and cash equivalents

    8,863,060     773,018     (641,937 )

Cash and cash equivalents—beginning of year

    1,042,956     269,938     911,875  
               

Cash and cash equivalents—end of year

  $ 9,906,016   $ 1,042,956   $ 269,938  
               
               

Supplemental disclosure of cash flow information:

Supplemental disclosure of non-cash activity:

   

See notes to combined financial statements.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements

Note 1—Description of Business and Summary of Significant Accounting Policies

Organization

        Pecos Gathering and Marketing, LLC ("Pecos") is a Colorado limited liability company ("LLC") headquartered in Austin, Texas. Transwest Leasing, LLC ("Transwest"), Blackhawk Gathering, LLC ("Blackhawk"), and Toro Operating Company, Inc. ("Toro") are all affiliated companies through common ownership. Striker Oilfield Services, LLC ("Striker") is a Texas LLC that has common ownership with Pecos but with different ownership percentages among its members. Pecos, Transwest, Blackhawk, Toro, and Striker are collectively referred to as the "Companies" in the combined financial statements.

Operations

        The Companies gather crude oil from producing leases in Texas and New Mexico and deliver it to truck unloading facilities. The truck unloading facilities are connected to common carrier pipelines or, in one case, with a direct company pipeline to a refinery. The Companies have crude oil treatment plants that treat and process crude oil to pipeline standards. The Companies lease trucks and trailers to related parties for the purpose of transporting and hauling oil. In south Texas, Striker operates primarily as a contract trucker for one significant customer and to a lesser extent buys and sells crude oil.

Principles of Combination

        The accompanying combined financial statements include the accounts of Pecos, Transwest, Blackhawk, Toro, and Striker. All Companies are affiliated and controlled by common ownership. All intercompany accounts and transactions have been eliminated in combination.

Use of Estimates

        The preparation of combined financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent liabilities at the date of the combined financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

        The Companies consider all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Companies continually monitor their positions with, and the credit quality of, the financial institutions with which they invest. As of the combined balance sheet date, and periodically throughout the year, the Companies have maintained balances in various operating accounts in excess of federally insured limits.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements (Continued)

Note 1—Description of Business and Summary of Significant Accounting Policies (Continued)

Accounts Receivable

        The Companies consider accounts receivable to be fully collectible; accordingly, no allowance for doubtful accounts has been established. Management reviews account balances regularly, and if amounts become uncollectible, the uncollectible portion is recorded to bad debt expense.

Concentrations of Credit Risk

        The Companies sell crude oil to two significant customers, Customer A, which operates a refinery at Big Springs, Texas, and Customer B at the Centurion pipeline in Midland and Andrews, Texas. As of December 31, 2011, Customer A and Customer B accounted for 67% and 33%, respectively, of accounts receivable. For the year ended December 31, 2011, Customer A and Customer B accounted for 62% and 35%, respectively, of total revenue. As of December 31, 2010, Customer A and Customer B accounted for 65% and 31%, respectively, of accounts receivable. For the year ended December 31, 2010, Customer A and Customer B accounted for 60% and 39%, respectively, of total revenue. For the year ended December 31, 2009, Customer A and Customer B accounted for 63% and 36%, respectively, of total revenue.

Inventory

        Inventory consists of crude oil and is stated at the lower of cost or market, determined using the first-in, first-out method.

Property, Plant, and Equipment

        Property, plant, and equipment are stated at cost. Depreciation on property, plant, and equipment is calculated utilizing the straight-line method over the estimated useful life, which ranges from three to fifteen years, net of an estimated salvage value of the property and equipment. The Companies periodically review the reasonableness of estimates regarding useful lives and salvage values of property, plant, and equipment based upon the Companies' experience with similar assets and conditions in the used revenue equipment market. Future changes in useful life or salvage value estimates, or fluctuations in market value that are not reflected in the estimated salvage value, would have an effect on the Companies' results of operations. Trucks and trailers are depreciated over a period of five years, facilities are depreciated over a period of fifteen years, and equipment is depreciated over a period of seven years.

Revenue Recognition

        The Companies record revenue from the sales of crude oil when the product is delivered, title has transferred, and collection is reasonably assured. The Companies record revenue from the hauling of crude oil when the product is delivered and collection is reasonably assured.

Income Taxes

        With the exception of Toro, the entities have elected to be treated as partnerships for income tax purposes. Accordingly, taxable income and losses from all entities, except Toro, are reported in the

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements (Continued)

Note 1—Description of Business and Summary of Significant Accounting Policies (Continued)

income tax returns of the respective members, and no provision for income taxes has been recorded in the Companies' combined financial statements. Toro is taxed as a C corporation, and during the years ended December 31, 2011 and 2010, it had an immaterial amount of net taxable income. Toro's current taxable income is also reduced due to the utilization of the remaining net operating loss carryforwards from prior years. Toro's deferred tax assets and deferred tax liabilities are immaterial as of December 31, 2011 and 2010.

        The Companies follow authoritative guidance on accounting for uncertainty in income taxes. With the exception of Toro, if taxing authorities were to disallow any tax positions taken by the Companies, the additional income taxes, if any, would be imposed on the members rather than the Companies. Tax positions taken by Toro are insignificant. Accordingly, there would only be a minimal impact on the Companies' combined financial statements.

        Interest and penalties associated with tax positions are recorded in the period assessed as general and administrative expenses. No interest or penalties have been assessed as of December 31, 2011, 2010, and 2009. The estimated returns for tax years subject to examination by tax authorities include 2007 and 2008 through the current period for state and federal tax reporting purposes, respectively.

Long-Lived Assets

        The Companies review their long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. The Companies look primarily to the estimated undiscounted future cash flows in their assessment of whether or not long-lived assets have been impaired. The Companies did not record any impairments during the years ended December 31, 2011, 2010, and 2009.

Fair Value of Financial Instruments

        The carrying amounts of financial instruments, including cash, receivables, prepaids, notes receivable, accounts payable and accrued expenses, approximated fair value as of December 31, 2011 and 2010 because of the relatively short maturity of these instruments.

        The carrying amounts of notes payable and debt issued approximate fair value as of December 31, 2011 and 2010 because interest rates on these instruments approximate market interest rates.

        The brokerage margin account is recorded at fair value as discussed in Note 5.

        The Companies disclose the fair value as determined for certain assets and liabilities and disclose how fair value is determined using a hierarchy for which these assets and liabilities are grouped, based on significant levels of inputs as follows:

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements (Continued)

Note 2—Balance Sheet Disclosures

        Property, plant, and equipment consist of the following:

 
  December 31,  
 
  2011   2010  

Trucks

  $ 11,907,676   $ 2,980,700  

Trailers

    6,040,215     2,349,316  

Facilities

    1,485,844     1,031,528  

Equipment

    885,387     615,544  

Other vehicles

    581,409     175,684  

Leasehold improvements

    56,790      

Computer equipment and software

    35,009     16,732  
           

    20,992,330     7,169,504  

Less accumulated depreciation

    (4,908,488 )   (2,807,540 )
           

  $ 16,083,842   $ 4,361,964  
           
           

        Depreciation expense for the years ended December 31, 2011, 2010, and 2009 was $2,100,948, $931,547, and $807,415, respectively.

        Accrued expenses consist of the following:

 
  December 31,  
 
  2011   2010  

Severance taxes payable

  $ 2,455,230   $ 993,610  

Other

    440,512     55,995  
           

  $ 2,895,742   $ 1,049,605  
           
           

Note 3—Line-of-Credit

        On December 31, 2011, the Companies entered into a new credit agreement (the "Agreement") with a bank. The Companies could have borrowed the lesser of the borrowing base as defined by the Agreement or $30,000,000. The borrowing base as of December 31, 2011 was $22,662,523. At December 31, 2011, the borrowings outstanding under this Agreement were $6,000,000. Borrowings accrued interest per annum equal to either the base rate advance or Eurodollar rate advance. The base rate advance was equal to the prime rate plus 2.75% (6.00% at December 31, 2011). The Eurodollar rate advance was based on the two-week, one-month, two-month, or three-month BBA LIBOR plus 4.00% (4.68% to 5.29% at December 31, 2011), as elected by the Companies and subject to certain restrictions. At December 31, 2011, all of the outstanding debt under the Agreement was based on the Eurodollar rate advance. All of the Companies' assets were pledged as collateral with the exception of Transwest. However, all assets of Transwest were pledged as collateral against the Companies' notes payable described in Note 4. The Agreement terminates and borrowings would have been due upon the occurrence of certain events or at the discretion of the lenders as defined in the Agreement. The

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements (Continued)

Note 3—Line-of-Credit (Continued)

Companies were required to meet certain financial covenants and were in compliance with all financial covenants at December 31, 2011.

        As of December 31, 2010, the Companies had a line-of-credit agreement with Bank of America. At December 31, 2010, the borrowings outstanding under this Agreement were $3,200,091. Interest accrued at one-month LIBOR plus 2.75% (3.013% at December 31, 2010). The Companies were required to meet certain financial covenants and were in compliance with all covenants at December 31, 2010. During 2011, the Companies paid the outstanding balance of the line-of-credit.

Note 4—Notes Payable

        Notes payable consist of the following:

 
  December 31,  
 
  2011   2010  

The Companies have various note payable agreements to third-party banks for certain trucks and trailers. Interest rates on these agreements range from 3.96% to 5.90%. The maturity dates on the notes payable range from January 2012 to March 2015. The Transwest portion of the Companies' assets are pledged as collateral, and there are guarantees by certain members of the Companies. 

  $ 12,425,349   $ 2,434,621  

Less current portion

    (4,861,915 )   (1,246,460 )
           

  $ 7,563,434   $ 1,188,161  
           
           

        Maturities of the notes payable are as follows:

Year Ending December 31,
   
 

2012

  $ 4,861,915  

2013

    4,640,705  

2014

    2,853,136  

2015

    69,593  
       

  $ 12,425,349  
       
       

Note 5—Derivatives

        The Companies routinely enter into contracts for the purchase and sale of crude oil at future delivery dates. The Companies enter into these contracts with the expectation that they will result in physical delivery of crude oil. The Companies account for these contracts as normal purchases and normal sales. Under this accounting policy election, the contracts are not recorded at fair value at the balance sheet dates; instead, the purchase or sale is recorded at the contracted value once the delivery occurs.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements (Continued)

Note 5—Derivatives (Continued)

        The Companies' crude oil purchase and sale contracts are priced based on various crude oil indices. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. The Companies have entered into certain financial derivative contracts, which consist primarily of crude oil futures contracts, as hedges against the risk that changes in the different index prices would reduce the margins between the purchase and the sale transactions.

        The Companies record these derivative contracts at fair value within accounts receivable on the combined balance sheets. The Companies value the derivative contracts using quoted prices in active markets for identical contracts and consider the fair value to be a Level 1 measurement in the fair value hierarchy. All of the contracts are maintained by a broker, and the Companies report these contracts, along with any related margin deposits, on a net basis on the combined balance sheets. The balance associated with these contracts, including related margin deposits, was $379,075 at December 31, 2011 and $249,399 at December 31, 2010, respectively.

        The Companies report the realized and unrealized gains and losses associated with these derivative contracts within product expenses in the combined statements of income. These gains and losses consist of the following:

 
  For the Years Ended December 31,  
 
  2011   2010   2009  

Unrealized gain (loss)

  $ 122,700   $ 38,860   $ 8,600  

Realized gain (loss)

    (250,150 )   12,549     (27,485 )
               

Total

  $ (127,450 ) $ 51,409   $ (18,885 )
               
               

        The Companies include net cash transfers to or from the brokerage account in investing cash flows in the combined statements of cash flows.

Note 6—Members' and Stockholders' Equity

        Individual capital accounts have been established based on the initial contribution to the Companies. Profits and losses are allocated to the members' capital accounts based upon percentages of ownership in the Companies. Additional capital contributions may be made upon a unanimous vote of all members. The Companies' operating agreements require available cash to be distributed at the end of each calendar year subject to certain limitations. As distributions made during the year ended December 31, 2011 were not pro rata with each member's ownership interest, as of December 31, 2011, Pecos and Striker accrued distributions of $808,113 and $1,200,000, respectively, payable to one or more members. These balances are included in distributions payable and have been shown as a liability on the combined balance sheets.

        Toro is the only affiliate with common stock. Each share of outstanding common stock is entitled to voting rights on matters affecting Toro.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements (Continued)

Note 7—Commitments and Contingencies

Letters-of-Credit

        On December 1, 2011, the Companies issued a $6,650,000 letter-of-credit that has not been drawn upon. This letter-of-credit expires in one to three month increments and can be renewed at the end of each term. The letter-of-credit was issued to secure the amounts owed to one of the Companies' crude oil suppliers. On June 1, 2012, the Companies issued a revision to this letter-of-credit for $4,950,000 to extend the letter-of-credit through July 31, 2012. The revised letters-of-credit have not had an impact on the Companies' combined 2011 results of operations.

        On June 1, 2012, the Companies issued a separate $3,000,000 letter-of-credit that has not been drawn upon. The letter-of-credit was issued to secure the amounts owed to one of the Companies' crude oil suppliers. No amounts were recorded in conjunction with the issuance of this letter-of-credit, which is irrevocable until December 31, 2012. The letters-of-credit incur interest at 3.75% per annum plus issuing fees of $300 and a $75 cancellation fee.

Asset Retirement Obligation

        The Companies are required to recognize the fair value of a liability for an asset retirement obligation when it is incurred (generally in the period in which they acquire, construct, or install an asset) if a reasonable estimate of fair value can be made. If a reasonable estimate cannot be made in the period the asset retirement obligation is incurred, the liability should be recognized when a reasonable estimate of fair value can be made.

        In order to determine fair value of such liability, the Companies must make certain estimates and assumptions, including, among other things, projected cash flows, a credit-adjusted risk-free interest rate, and an assessment of market conditions, that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time.

        The Companies have determined that they are obligated by contractual or regulatory requirements to remove certain of their assets or perform other remediation of the sites where such assets are located upon the retirement of those assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including estimated settlement dates, future retirement costs, future inflation rates, and the credit-adjusted risk-free interest rates. However, the Companies do not believe the present value of such asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of the Companies' facilities, is material to their financial position or results of operations.

Litigation

        In the normal course of business, the Companies are party to litigation from time to time. The Companies maintain insurance to cover certain actions and believe that resolution of such litigation will not have a material adverse effect on the Companies.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements (Continued)

Note 8—Related Party Transactions

        In February 2010, the Companies entered into a note receivable agreement with a member for $200,000. The note was due February 2013 and had an interest rate of 2% per annum. During the years ended December 31, 2011 and 2010, the Companies' distributions totaling $66,547 and $59,844, respectively, were applied to this member note receivable, which are reflected as non-cash distributions on the combined statements of cash flows. Subsequent to December 31, 2011, the remaining note receivable balance was collected.

        During the year ended December 31, 2011, the Companies paid $170,000 in management fees to a related party, which is included in general and administrative expenses on the combined statements of income.

        The Companies also have various related party receivables and payables outstanding. Receivables from related parties totaled $85,805 and $38,296 at December 31, 2011 and 2010, respectively. Payables due to related parties totaled $12,000 and $30,348 at December 31, 2011 and 2010, respectively. The Companies also have a $250,000 deposit with a related party at December 31, 2011 and 2010.

Note 9—Subsequent Events

        Midstream Operations, LLC ("Midstream") was formed on January 1, 2012. Midstream is a management company that is owned by two of the Companies' members and stockholders and allocates general and administrative overhead charges to the Companies. These allocated charges include salaries and office expenses.

        On October 23, 2012, the Companies, including Midstream, entered into an Equity Purchase Agreement (the "NGL Agreement") with NGL Energy Partners LP ("NGL") to purchase all of the equity in Pecos, Transwest, Blackhawk, Striker, and Midstream, which closed November 2012. Under the NGL Agreement, NGL would also have first right of refusal to purchase one of the two properties owned by Toro. The Companies are also required to provide remediation for this property, as well as provide assistance and set-up of a new processing facility to be operated by NGL. As part of the NGL Agreement, the line-of-credit was paid in full as well as a portion of the notes payable.

        The Companies have evaluated all subsequent events through January 14, 2013, which is the date the combined financial statements were available for issuance.

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INDEPENDENT ACCOUNTANTS' REVIEW REPORT

Board of Directors, Members, and Stockholders
Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC,
Blackhawk Gathering, LLC, Midstream Operations, LLC, Toro
Operating Company, Inc., and Striker Oilfield Services, LLC
Austin, Texas

        We have reviewed the accompanying combined balance sheets of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, LLC, Midstream Operations, LLC, Toro Operating Company, Inc., and Striker Oilfield Services, LLC (the "Companies") as of September 30, 2012 and 2011, and the related combined statements of income, changes in members' and stockholders' equity, and cash flows for the nine months ended September 30, 2012 and 2011. A review includes primarily applying analytical procedures to management's financial data and making inquiries of management. A review is substantially less in scope than an audit, the objective of which is the expression of an opinion regarding the combined financial statements as a whole. Accordingly, we do not express such an opinion.

        Management is responsible for the preparation and fair presentation of the combined financial statements in accordance with accounting principles generally accepted in the United States of America and for designing, implementing, and maintaining internal controls relevant to the preparation and fair presentation of the combined financial statements.

        Our responsibility is to conduct the review in accordance with Statements on Standards for Accounting and Review Services issued by the American Institute of Certified Public Accountants. Those standards require us to perform procedures to obtain limited assurance that there are no material modifications that should be made to the combined financial statements. We believe that the results of our procedures provide a reasonable basis for our report.

        Based on our reviews, we are not aware of any material modifications that should be made to the accompanying combined financial statements in order for them to be in conformity with accounting principles generally accepted in the United States of America.

        The combined financial statements for the year ended December 31, 2011, were audited by us, and we expressed an unqualified opinion on them in our report dated January 14, 2013, but we have not performed any auditing procedures since that date.

/s/ EKS&H, LLLP

January 14, 2013
Denver, Colorado

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Combined Balance Sheets

(See Independent Accountants' Review Report)

 
  September 30,
2012
  December 31
2011
 
 
  (unaudited)
  (audited)
 

Assets

             

Current assets

   
 
   
 
 

Cash and cash equivalents

  $ 7,749,810   $ 9,906,016  

Accounts receivable

    83,432,762     51,860,802  

Inventory

    1,531,145     1,348,826  

Due from related parties

    360,276     85,805  

Prepaid expenses and other current assets

    965,903     401,727  
           

Total current assets

    94,039,896     63,603,176  
           

Non-current assets

             

Property, plant, and equipment, net of accumulated depreciation of $8,029,823 and $4,908,488, at September 30, 2012 and December 31, 2011, respectively

    21,662,896     16,083,842  

Land

    236,453     230,253  

Deposits—related party

        250,000  

Deposits

        9,434  
           

Total non-current assets

    21,899,349     16,573,529  
           

Total assets

  $ 115,939,245   $ 80,176,705  
           
           

Liabilities and Stockholders' Equity

             

Current liabilities

   
 
   
 
 

Line of credit

  $ 5,000,000   $ 6,000,000  

Accounts payable—crude oil purchases

    52,259,802     32,974,766  

Accounts payable

    1,837,789     832,660  

Accrued expenses

    4,680,551     2,895,742  

Due to related parties

        12,000  

Notes payable—current portion

    7,307,463     4,861,915  

Distributions payable

        2,008,113  
           

Total current liabilities

    71,085,605     49,585,196  

Non-current liabilities

             

Long-term debt, less current portion

    8,168,677     7,563,434  
           

Total liabilities

    79,254,282     57,148,630  
           

Commitments and contingencies (Note 7)

             

Members' and stockholders' equity

             

Common stock, 30,000 shares authorized, 15,594 shares outstanding, par value $0.10

    1,559     1,559  

Additional paid-in capital

    582,822     582,822  

Retained earnings (accumulated deficit)

    21,799     82,037  

Note receivable—member

        (73,609 )

Members' equity

    36,078,783     22,435,266  
           

Total members' and stockholders' equity

    36,684,963     23,028,075  
           

Total liabilities and members' and stockholders' equity

  $ 115,939,245   $ 80,176,705  
           
           

   

See notes to unaudited combined financial statements.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Unaudited Combined Statements of Income

(See Independent Accountants' Review Report)

 
  Nine Months Ended
September 30,
 
 
  2012   2011  

Revenues

             

Crude oil sales

  $ 637,163,966   $ 337,620,173  

Crude oil hauling

    22,117,354     8,832,916  

Rental revenue—related parties

    51,032      
           

Total revenues

    659,332,352     346,453,089  
           

Product expenses

    625,771,712     330,479,968  
           

Operating expenses

             

Transportation expenses

    1,234,691     1,315,972  

Personnel expenses

    5,698,940     2,839,012  

Equipment and facilities' expenses

    577,961     807,565  

General and administrative expenses

    1,641,151     1,344,730  

Depreciation

    3,283,939     1,345,324  
           

Total operating expenses

    12,436,682     7,652,603  
           

Other (expense) income

             

Interest expense

    (877,625 )   (421,448 )

Interest income

    13,506     5,701  

Loss on disposal of assets

    (660 )    
           

Total other expense, net

    (864,779 )   (415,747 )
           

Net income

  $ 20,259,179   $ 7,904,771  
           
           

   

See notes to unaudited combined financial statements.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Unaudited Combined Statement of Changes in Members' and Stockholders' Equity

Nine Months Ended September 30, 2012

(See Independent Accountants' Review Report)

 
   
   
   
   
  Pecos Gathering and
Marketing, LLC,
Transwest Leasing, LLC,
Blackhawk
Gathering, LLC,
Midstream
Operations, LLC,
and Striker Oilfield
Services, LLC
   
 
 
  Toro Operating, Inc.    
 
 
  Common Stock    
   
   
 
 
  Additional
Paid-In
Capital
  Retained
Earnings
  Note
Receivable
Members'
  Members'
Equity
  Total
Stockholders'
Equity
 
 
  Shares   Par Value  

Balance—December 31, 2011

    15,594   $ 1,559   $ 582,822   $ 82,037   $ (73,609 ) $ 22,435,266   $ 23,028,075  

Payment on note receivable from member

                    73,609         73,609  

Distributions

                        (6,925,900 )   (6,925,900 )

Contributions

                        250,000     250,000  

Net income (loss)

                (60,238 )       20,319,417     20,259,179  
                               

Balance—September 30, 2012

    15,594   $ 1,559   $ 582,822   $ 21,799   $   $ 36,078,783   $ 36,684,963  
                               
                               

   

See notes to unaudited combined financial statements.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Unaudited Combined Statements of Cash Flows

(See Independent Accountants' Review Report)

 
  Nine Months Ended
September 30,
 
 
  2012   2011  

Cash flows from operating activities

             

Net income

  $ 20,259,179   $ 7,904,771  
           

Adjustments to reconcile net income to net cash provided by operating activities

             

Depreciation

    3,283,939     1,345,324  

Loss on sale of assets

    660      

Gain on derivatives

    (582,129 )   (209,015 )

Changes in assets and liabilities

             

Accounts receivable

    (30,989,831 )   (13,671,976 )

Inventory

    (182,319 )   506,807  

Due to/from related parties, net

    (286,471 )   (78,748 )

Prepaid expenses and other current assets

    (554,742 )   (71,455 )

Deposits

    250,000      

Accounts payable—crude oil purchases

    19,285,036     8,432,609  

Accounts payable

    1,005,129     (868,615 )

Accrued expenses

    1,784,809     963,119  
           

    (6,985,919 )   (3,651,950 )
           

Net cash provided by operating activities

    13,273,260     4,252,821  
           

Cash flows from investing activities

             

Purchase of land, property, plant, and equipment

    (1,779,592 )   (777,184 )

Proceeds from sale of property, plant, and equipment

    444,802      

Cash flows from derivatives

        (257,126 )
           

Net cash used in investing activities

    (1,334,790 )   (1,034,310 )
           

Cash flows from financing activities

             

Borrowings from line-of-credit

    6,000,000     114,320,000  

Payments on line-of-credit

    (7,000,000 )   (113,020,000 )

Payments on notes payable

    (4,484,272 )   (1,669,878 )

Member contributions

    250,000      

Member distributions

    (8,860,404 )   (948,739 )
           

Net cash used in financing activities

    (14,094,676 )   (1,318,617 )
           

Net (decrease) increase in cash and cash equivalents

    (2,156,206 )   1,899,894  

Cash and cash equivalents—beginning of period

    9,906,016     1,042,956  
           

Cash and cash equivalents—end of period

  $ 7,749,810   $ 2,942,850  
           
           

Supplemental disclosure of cash flow information:

Supplemental disclosure of non-cash activity:

   

See notes to unaudited combined financial statements.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements

(See Independent Accountants' Review Report)

Note 1—Description of Business and Summary of Significant Accounting Policies

Organization

        Pecos Gathering and Marketing, LLC ("Pecos") is a Colorado limited liability company ("LLC") headquartered in Austin, Texas. Transwest Leasing, LLC ("Transwest"), Blackhawk Gathering, LLC ("Blackhawk"), Midstream Operations, LLC ("Midstream"), and Toro Operating Company, Inc. ('Toro") are all affiliated companies through common ownership. Striker Oilfield Services, LLC ("Striker") is a Texas LLC that has common ownership with Pecos but with different ownership percentages among its members. Pecos, Transwest, Blackhawk, Midstream, Toro, and Striker are collectively referred to as the "Companies" in the combined financial statements.

Financial Statement Presentation

        The Companies have prepared these unaudited interim combined financial statements included herein pursuant to the rules and regulations of the United States Securities and Exchange Commission. In the Companies' opinion, the unaudited interim combined financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly, in all material respects, the combined financial position as of September 30, 2012, the interim results of operations for the nine months ended September 30, 2012 and 2011, and cash flows for the nine months ended September 30, 2012. These interim statements have not been audited. The balance sheet as of December 31, 2011 was derived from the Companies' audited combined financial statements. The interim combined financial statements contained herein should be read in conjunction with our audited combined financial statements, including the notes thereto, for the year ended December 31, 2011.

Operations

        The Companies gather crude oil from producing leases in Texas and New Mexico and deliver it to truck unloading facilities. The truck unloading facilities are connected to common carrier pipelines or, in one case, to a direct company pipeline to a refinery. The Companies have crude oil treatment plants that treat and process crude oil to pipeline standards. The Companies lease trucks and trailers to related parties for the purpose of transporting and hauling oil. In South Texas, Striker operates primarily as a contract trucker for one significant customer and, to a lesser extent, buys and sells crude oil.

Principles of Combination

        The accompanying combined financial statements include the accounts of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, LLC, Midstream Operations, LLC, Toro Operating Company, Inc., and Striker Oilfield Services, LLC. All Companies are affiliated and controlled by common ownership. All intercompany accounts and transactions have been eliminated in combination.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 1—Description of Business and Summary of Significant Accounting Policies (Continued)

Use of Estimates

        The preparation of combined financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the combined financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

        The Companies considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Companies continually monitors its positions with, and the credit quality of, the financial institutions it invests with. As of the balance sheet date, and periodically throughout the year, the Company has maintained balances in various operating accounts in excess of federally insured limits.

Accounts Receivable

        The Companies consider accounts receivable to be fully collectible; accordingly, no allowance for doubtful accounts is required. Management reviews account balances regularly, and, if amounts become uncollectible, the uncollectible portion is recorded to bad debt expense.

Concentrations of Credit Risk

        The Companies sell crude oil to two significant customers, Customer A, which operates a refinery in Big Springs, Texas, and Customer B, at the Centurion pipeline in Midland and Andrews, Texas. As of September 30, 2012, Customer A and Customer B accounted for 59% and 18%, respectively, of accounts receivable. As of December 31, 2011, Customer A and Customer B accounted for 67% and 33%, respectively, of accounts receivable. For the nine months ended September 30, 2012, Customer A and Customer B accounted for 57% and 19%, respectively, of total revenue. For the nine months ended September 30, 2011, Customer A and Customer B accounted for 60% and 35%, respectively, of total revenue.

Inventory

        Inventory consists of crude oil and is stated at the lower of cost or market, determined using the first-in, first-out method.

Property, Plant, and Equipment

        Property, plant, and equipment are stated at cost. Depreciation on property, plant, and equipment is calculated utilizing the straight-line method over the estimated useful life, which ranges from three to fifteen years, net of an estimated salvage value of the property and equipment. The Companies periodically review the reasonableness of estimates regarding useful lives and salvage values of property, plant, and equipment based upon the Companies' experience with similar assets and

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 1—Description of Business and Summary of Significant Accounting Policies (Continued)

conditions in the used revenue equipment market. Future changes in useful life or salvage value estimates, or fluctuations in market value that are not reflected in the estimated salvage value, would have an effect on the Companies' results of operations. Trucks and trailers are depreciated over a period of five years, facilities are depreciated over a period of fifteen years, and equipment is depreciated over a period of seven years.

Revenue Recognition

        The Companies record revenue from the sales of crude oil when the product is delivered, title has transferred, and collection is reasonably assured. The Companies record revenue from the hauling of crude oil when the product is delivered and collection is reasonably assured.

        Revenue on the rental of trucks and trailers is recognized on a straight-line basis over the term of the lease. The Companies' standard lease agreements are non-cancelable operating leases and provide for monthly lease payments for three years.

Income Taxes

        With the exception of Toro, the entities have elected to be treated as partnerships for income tax purposes. Accordingly, taxable income and losses from all entities, except for Toro, are reported in the income tax returns of the respective members, and no provision for income taxes has been recorded in the Companies' combined financial statements. Toro is taxed as a C corporation, and during the nine months ended September 30, 2012, it had an immaterial amount of net taxable income. Toro's current taxable income is also reduced due to the utilization of the remaining net operating loss carryforwards from prior years. Toro's deferred tax assets and deferred tax liabilities are immaterial as of September 30, 2012.

        The Companies follow authoritative guidance on accounting for uncertainty in income taxes. With the exception of Toro, if taxing authorities were to disallow any tax positions taken by the Companies, the additional income taxes, if any, would be imposed on the members rather than the Companies. Tax positions taken by Toro are insignificant. Accordingly, there would only be a minimal impact on the Companies' combined financial statements.

Income Taxes (continued)

        Interest and penalties associated with tax positions are recorded in the period assessed as general and administrative expenses. No interest or penalties have been assessed as of September 30, 2012. The estimated returns for tax years subject to examination by tax authorities include 2007 and 2008 through the current period for state and federal tax reporting purposes, respectively.

Long-Lived Assets

        The Companies review the long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. The Companies look primarily to the undiscounted future cash flows in its assessment of whether or not long-lived

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 1—Description of Business and Summary of Significant Accounting Policies (Continued)

assets have been impaired. The Companies did not record any impairments during the nine months ended September 30, 2012 and 2011.

Fair Value of Financial Instruments

        The carrying amounts of financial instruments including cash and cash equivalents, short-term investments, receivables, prepaids, notes receivable, accounts payable, and accrued expenses approximated fair value as of September 30, 2012 because of the relatively short maturity of these instruments.

        The carrying amounts of notes payable and debt issued approximate fair value as of September 30, 2012 because interest rates on these instruments approximate market interest rates.

        The brokerage margin account is recorded at fair value as discussed in Note 5.

        The Companies disclose the fair value as determined for certain assets and liabilities and disclose how fair value is determined using a hierarchy for which these assets and liabilities are grouped, based on significant levels of inputs as follows:

Level 1:   Quoted prices in active markets for identical assets or liabilities;

Level 2:

 

Quoted prices in active markets for similar assets and liabilities and inputs that are observable for the asset or liability; or

Level 3:

 

Unobservable inputs in which there is little or no market data, which requires the reporting entity to develop its own assumptions.

Note 2—Balance Sheet Disclosures

        Property and equipment consist of the following:

 
  September 30,
2012
  December 31.
2011
 

Trucks

  $ 16,162,106   $ 11,907,676  

Trailers

    9,392,446     6,040,215  

Equipment

    1,878,639     885,387  

Facilities

    1,564,205     1,485,844  

Other vehicles

    593,846     581,409  

Leasehold improvements

    55,232     56,790  

Computer equipment and software

    46,245     35,009  
           

    29,692,719     20,992,330  

Less accumulated depreciation

    (8,029,823 )   (4,908,488 )
           

  $ 21,662,896   $ 16,083,842  
           
           

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 2—Balance Sheet Disclosures (Continued)

        Depreciation expense for the nine months ended September 30, 2012 and 2011 was $3,283,939 and $1,345,324, respectively.

        Accrued expenses consist of the following:

 
  September 30,
2012
  December 31,
2011
 

Severance taxes payable

  $ 3,772,927   $ 2,455,230  

Other

    907,624     440,512  
           

  $ 4,680,551   $ 2,895,742  
           
           

Note 3—Line-of-Credit

        On December 13, 2011, the Companies entered into a new credit agreement ("Agreement") with a bank. The Companies could have borrowed the lesser of the borrowing base, as defined by the Agreement, or $30,000,000. The borrowing base as of September 30, 2012 was $34,248,095. At September 30, 2012, there was $5,000,000 outstanding under this Agreement. Borrowings accrued interest per annum equal to either the base-rate advance or Eurodollar-rate advance. The base-rate advance was equal to the prime rate plus 2.75% (6.00% at September 30, 2012). The Eurodollar rate advance was based on the two-week, one-month, two-month, or three-month BBA LIBOR plus 4.00% (4.20% to 4.42% at September 30, 2012), as elected by the Companies and subject to certain restrictions. At September 30, 2012, all of the outstanding debt under the Agreement was based on the Eurodollar-rate advance. All of the Companies' assets were pledged as collateral with the exception of Transwest. The assets of Transwest are pledged as collateral against the Companies' notes payable described in Note 4. The Agreement terminates and borrowings were due upon the occurrence of certain events or at the discretion of the lenders, as defined in the Agreement. The Companies were required to meet certain financial covenants and were in compliance with all financial covenants at September 30, 2012.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 4—Notes Payable

        Notes payable consist of the following:

 
  September 30,
2012
  December 31
2011
 

The Companies have various note payable agreements to third-party banks for certain trucks and trailers. Interest rates on these agreements range from 3.82% to 5.90%. The maturity dates on the notes payable range from April 2013 to September 2015. The Transwest portion of the Companies' assets are pledged as collateral, and there are guarantees by certain members and stockholders of the Companies. 

  $ 15,476,140   $ 12,425,349  

Less current portion

    (7,307,463 )   (4,861,915 )
           

  $ 8,168,677   $ 7,563,434  
           
           

        Maturities of the notes payable are as follows:

Year Ending December 31,
   
 

2012 (three months)

  $ 2,012,471  

2013

    7,087,231  

2014

    5,407,545  

2015

    968,893  
       

  $ 15,476,140  
       
       

Note 5—Derivatives

        The Companies routinely enter into contracts for the purchase and sale of crude oil at future delivery dates. The Companies enter into these contracts with the expectation that they will result in physical delivery of crude oil. The Companies account for these contracts as normal purchases and normal sales. Under this accounting policy election, the contracts are not recorded at fair value at the balance sheet dates; instead, the purchase or sale is recorded at the contracted value once the delivery occurs.

        The Companies have entered into certain financial derivative contracts, which consist primarily of crude oil futures contracts. The Companies record these derivative contracts at fair value within accounts receivable on the condensed combined balance sheets. The Companies value the derivative contracts using quoted prices in active markets for identical contracts and considers the fair value to be a Level 1 measurement in the fair value hierarchy. All of the contracts are maintained by a broker, and the Companies report these contracts, along with any related margin deposits, on a net basis on the combined balance sheets. The balance associated with these contracts, including related margin deposits, was $961,205 at September 30, 2012 and $379,075 at December 31, 2011, respectively.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 5—Derivatives (Continued)

        The Companies report the realized and unrealized gains and losses associated with these derivative contracts within other income (expense) in the combined statements of income. These gains and losses consist of the following:

 
  For the Nine Months
Ended September 30,
 
 
  2012   2011  

Unrealized gain (loss)

  $ (79,480 ) $ (599,500 )

Realized gain (loss)

    661,609     808,515  
           

Total

  $ 582,129   $ 209,015  
           
           

        The Companies include net cash transfers to or from the brokerage account in investing cash flows in the combined statements of cash flows.

Note 6—Members' and Stockholders' Equity

        Individual capital accounts have been established based on the initial contribution to the Companies. Profits and losses are allocated to the members' capital accounts based upon percentages of ownership in the Companies. Additional capital contributions may be made upon a unanimous vote of all members. The Companies' operating agreements require available cash to be distributed at the end of each calendar year, subject to certain limitations.

        Toro is the only affiliate with common stock. Each share of outstanding common stock is entitled to voting rights on matters affecting Toro.

Note 7—Commitments and Contingencies

Letters-of-Credit

        On December 1, 2011, the Companies issued a $6,650,000 letter-of-credit that has not been drawn upon. This letter-of-credit expires in one- to three-month increments and can be renewed at the end of each term. The letter-of-credit was issued to secure the amounts owed to one of the Companies' crude oil suppliers. On June 1, 2012, the Companies issued a revision to this letter-of-credit for $4,950,000 to extend the letter-of-credit through July 31, 2012. The revised letter-of-credit has not had an impact on the Companies' combined 2011 results of operations.

        On June 1, 2012, the Companies issued a separate $3,000,000 letter-of-credit that has not been drawn upon. The letter-of-credit was issued to secure the amounts owed to one of the Companies' crude oil suppliers. No amounts were recorded in conjunction with the issuance of this letter-of-credit, which is irrevocable until December 31, 2012.

        The letters-of-credit incur interest at 3.75% per annum plus issuing fees of $300 and a $75 cancellation fee.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 7—Commitments and Contingencies (Continued)

Asset Retirement Obligations

        The Companies are required to recognize the fair value of a liability for an asset retirement obligation when it is incurred (generally in the period in which they acquire, construct, or install an asset) if a reasonable estimate of fair value can be made. If a reasonable estimate cannot be made in the period the asset retirement obligation is incurred, the liability should be recognized when a reasonable estimate of fair value can be made.

        In order to determine fair value of such liability, the Companies must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free interest rate, and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time.

        The Companies have determined that they are obligated by contractual or regulatory requirements to remove certain of their assets or perform other remediation of the sites where such assets are located upon the retirement of those assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including estimated settlement dates, future retirement costs, future inflation rates, and the credit-adjusted risk-free interest rates. However, the Companies do not believe the present value of such asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of the Companies facilities, is material to their financial position or results of operations.

Litigation

        In the normal course of business, the Companies are party to litigation from time to time. The Companies maintain insurance to cover certain actions and believe that resolution of such litigation will not have a material adverse effect on the Companies.

Note 8—Related Party Transactions

        In February 2010, the Companies entered into a note receivable agreement with a member for $200,000. The note was due February 2013 and had an interest rate of 2% per annum. During the nine-month period ended September 30, 2012, distributions totaling $73,609 were applied to this member note receivable, which are reflected as non-cash distributions on the combined statement of cash flows. During the nine-month period ended September 30, 2012, the note was paid off.

        During the nine-month periods ended September 30, 2012 and 2011, the Companies paid $153,000 and $119,000, respectively, in management fees to a related party, which is included in general and administrative expenses on the combined statements of income.

        The Companies also have various related party receivables outstanding totaling $360,276 at September 30, 2012. There were no related party payables outstanding as of September 30, 2012.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 9—Subsequent Events

        On October 23, 2012, the Companies entered into an Equity Purchase Agreement (the "NGL Agreement") with NGL Energy Partners LP ("NGL") to purchase all of the equity in Pecos, Transwest, Blackhawk, Striker, and Midstream, which closed November 2012. Under the NGL Agreement, NGL would also have first right of refusal to purchase one of the two properties owned by Toro. The Companies are also required to provide remediation for this property, as well as provide assistance and set-up of a new processing facility to be operated by NGL. As part of the NGL Agreement, the line-of-credit was paid in full, as well as a portion of the notes payable.

        The Companies have evaluated all subsequent events through January 14, 2013, which is the date the unaudited combined financial statements were available for issuance.

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Independent Auditor's Report

General Partner
Oilfield Water Lines, LP
Dallas, Texas

        We have audited the accompanying consolidated financial statements of Oilfield Water Lines, LP and its subsidiaries, which comprise the consolidated balance sheet as of December 31, 2012, and the related consolidated statements of operations, changes in partners' capital, and cash flows for the period from inception (August 6, 2012) to December 31, 2012, and the related notes to the consolidated financial statements.

Management's Responsibility for the Financial Statements

        Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

        Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

        An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

        We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Oilfield Water Lines, LP and its subsidiaries as of December 31, 2012, and the results of their operations and their cash flows for the period from inception (August 6, 2012) to December 31, 2012 in accordance with accounting principles generally accepted in the United States of America.

Basis of Presentation

        As discussed in Note 10, the operating subsidiaries of Oilfield Water Lines, LP, were sold on August 2, 2013.

/s/ BDO USA, LLP
Dallas, Texas
September 27, 2013

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Oilfield Water Lines, LP

Consolidated Balance Sheet

 
  December 31,
2012
 

Assets

       

Current assets

       

Cash and cash equivalents

  $ 3,853,865  

Accounts receivable—trade

    3,834,236  

Prepaid expenses and other

    323,158  
       

Total current assets

    8,011,259  

Property and equipment, net

   
23,386,066
 

Goodwill

    18,682,609  

Other assets

    325,749  
       

Total assets

  $ 50,405,683  
       
       

Liabilities and Capital

       

Current liabilities

       

Accounts payable—trade

  $ 4,333,007  

Insurance notes payable

    248,714  

Accrued expenses

    425,776  

Related party debt

    1,676,357  
       

Total current liabilities

    6,683,854  
       

Commitments and contingencies (Note 8)

       

Capital

   
 
 

General partner (0.1%)

    19,466  

Limited partners (99.9%)

    37,369,386  
       

Total partners' capital

    37,388,852  
       

Non-controlling interests

    6,332,977  

Total capital

   
43,721,829
 
       

Total liabilities and capital

  $ 50,405,683  
       
       

   

The accompanying notes are an integral part of these consolidated financial statements.

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Oilfield Water Lines, LP

Consolidated Statement of Operations

 
  Period from inception
(August 6, 2012) to
December 31, 2012
 

Revenues

       

Crude oil sales

  $ 4,337,774  

Water disposal services

    1,338,726  
       

Total revenues

    5,676,500  

Expenses

   
 
 

Well servicing

    1,614,710  

General and administrative

    429,881  

Acquisition transaction costs

    328,509  

Depreciation and amortization

    269,239  
       

Total expenses

    2,642,339  

Operating income

   
3,034,161
 

Other expense

   
 
 

Interest expense

    (17 )

Interest expense—related party

    (176,357 )

Interest expense—non-controlling interest

    (4,750,000 )
       

Total other expense

    (4,926,374 )

Loss before income taxes

   
(1,892,213

)

Provision for income taxes

   
(34,368

)
       

Net loss

    (1,926,581 )

Net income attributable to non-controlling interest

   
936,477
 
       

Net loss attributable to partners

  $ (2,863,058 )
       
       

   

The accompanying notes are an integral part of these consolidated financial statements.

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Oilfield Water Lines, LP

Consolidated Statement of Changes in Partners' Capital

 
  General
Partner
  Limited
Partners
  Non-
Controlling
Interest
  Total
Equity
 

Balance at inception (August 6, 2012)

  $   $   $   $  

Contributions

    22,330     41,306,056         41,328,386  

Purchase of non-controlling interest

            6,660,000     6,660,000  

Distributions

        (1,076,476 )   (1,263,500 )   (2,339,976 )

Net (loss) income

    (2,864 )   (2,860,194 )   936,477     (1,926,581 )
                   

Balance at December 31, 2012

  $ 19,466   $ 37,369,386   $ 6,332,977   $ 43,721,829  
                   
                   

   

The accompanying notes are an integral part of these consolidated financial statements.

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Oilfield Water Lines, LP

Consolidated Statement of Cash Flows

 
  Period from inception
(August 6, 2012) to
December 31, 2012
 

Cash flows from operating activities

       

Net loss

  $ (1,926,581 )

Adjustments to reconcile net loss to net cash provided by operating activities:

       

Depreciation and amortization expense

    269,239  

Interest expense—non-controlling interest

    4,750,000  

Changes in operating assets and liabilities, net of amounts acquired in acquisitions:

       

Accounts receivable

    (930,696 )

Prepaid expenses and other current assets

    (32,622 )

Other assets

    (325,749 )

Accounts payable—trade

    3,412,861  

Accrued expenses and other liabilities

    279,332  

Related party debt

    176,357  
       

Net cash provided by operating activities

    5,672,141  
       

Cash flows from investing activities

       

Purchases of property and equipment

    (7,308,995 )

Acquisitions of subsidiaries, net of cash acquired

    (24,987,691 )
       

Net cash used by investing activities

    (32,296,686 )
       

Cash flows from financing activities

       

Payments on acquisition debt

    (8,510,000 )

Contributions from partners

    41,328,386  

Distributions to non-controlling interests

    (1,263,500 )

Withdrawals by partners

    (1,076,476 )
       

Net cash provided by financing activities

    30,478,410  
       

Net increase in cash and cash equivalents

    3,853,865  

Cash and cash equivalents

   
 
 

Beginning of period

     
       

End of period

  $ 3,853,865  
       
       

   

The accompanying notes are an integral part of these consolidated financial statements.

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Oilfield Water Lines, LP

Notes to Consolidated Financial Statements

1. Organization and Nature of Business

        Oilfield Water Lines, LP (the "Partnership") is a Texas Limited Partnership formed on August 6, 2012. The Partnership is engaged in the water services and hauling businesses, the assets of which primarily include water treatment and disposal facilities, trucks and trailers.

        The general partner of the Partnership is Oilfield Water Lines GP, LLC.

2. Summary of Significant Accounting Policies

Principles of Consolidation

        The Partnership's consolidated financial statements as of December 31, 2012 include the accounts of Oilfield Water Lines, LP and its controlled subsidiaries, which are HR OWL, LLC, OWL Operating, LLC, OWL Pearsall SWD, LLC, OWL Karnes SWD, LLC, OWL Cotulla SWD, LLC, OWL Nixon SWD, LLC, OWL Lotus, LLC and Lotus Oilfield Services, LLC. All significant intercompany balances and transactions have been eliminated in consolidation.

Use of Estimates

        The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of the Partnership's assets, liabilities, revenues, expenses and costs. These estimates are based on management's knowledge of current events, historical experience, and various other assumptions that it believes to be reasonable under the circumstances.

        Critical estimates management makes in the preparation of the Partnership's consolidated financial statements include the collectability of accounts receivable, estimates of useful lives and recoverability of property, plant and equipment, valuation of goodwill and accruals for various commitments and contingencies, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Revenue Recognition

        The Partnership generates revenues from the gathering, hauling, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recovered hydrocarbons.

        The Partnership generally recognizes revenue when the customer takes ownership or assumes the risk of loss; collection of the relevant receivable is probable, persuasive evidence of arrangement exists; and the transaction price is fixed or determinable.

        The Partnership records revenues from crude oil sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. The Partnership records water disposal revenues at the time the services are performed, which is upon receipt of the wastewater at the Partnership's disposal facilities.

        The Partnership recognizes revenue upon completion of hauling services, provided collection of the relevant receivables is probable, persuasive evidence of an arrangement exists, and the price is fixed or determinable.

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Oilfield Water Lines, LP

Notes to Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

Cash and Cash Equivalents

        The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

        The Partnership grants unsecured credit to customers under normal industry standards and terms and evaluates each customer's creditworthiness as well as general economic conditions. An allowance for doubtful accounts is established, if necessary, based on management's assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes. There were no allowances for doubtful accounts as of December 31, 2012.

Property and Equipment

        Property and equipment are recorded at cost. Improvements or betterments that extend the useful life of the assets are capitalized. Expenditures for maintenance and repairs are charged to expense when incurred. The costs of assets retired or otherwise disposed of and the related accumulated depreciation are eliminated from the accounts in the period of disposal. Gains or losses resulting from property disposals are credited or charged to operations currently. Depreciation is recorded using the straight-line method over the estimated useful lives of the assets.

Goodwill

        Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Goodwill is not amortized, but instead the Partnership evaluates goodwill for impairment annually, or more often if events or circumstances indicate that the asset might be impaired.

Impairments of Long-Lived Assets

        In accordance with Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") Topic 360 "Property, Plant and Equipment", long-lived assets, such as property and equipment and finite-lived intangibles subject to amortization, are reviewed for impairment whenever events or circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Partnership evaluated its asset group in accordance with ASC 360 for the year ended December 31, 2012 and concluded that no impairment of long-lived assets existed.

Non-Controlling Interests

        The Partnership has four consolidated subsidiaries in which outside parties own interests. The Partnership's ownership interests in these subsidiaries range from 74% to 75%. The non-controlling

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Oilfield Water Lines, LP

Notes to Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

interest shown in the Partnership's consolidated financial statements represents the other owners' interests in these entities.

Environmental

        The Partnership is subject to extensive federal, state, and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the adverse environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.

        The Partnership may be subject to removal and restoration costs upon retirement of its facilities. Management is currently unable to predict when, or if, these facilities will become obsolete and require restoration. Accordingly, no provision for this liability has been made in these financial statements as both the amount and timing of such potential future costs are indeterminable.

Income Tax

        The Partnership is not subject to federal income taxes; instead, the taxable earnings or losses of the Partnership are reported by the Partners in their separate income tax returns. Accordingly, no provision for federal income taxes has been made in these financial statements. The Partnership is subject to the Texas margin tax, and a provision for this expense is included in the statement of operations.

        The Partnership recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Partnership has evaluated tax positions taken or expected to be taken in the course of preparing the Partnership's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Therefore, no tax expense, including any interest and penalties, was recorded in the current period. All tax years since inception of the Partnership (August 6, 2012) remain open.

Comprehensive Income

        Comprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Partnership has no items of comprehensive income other than net income in any period presented. Therefore, net income as presented in the consolidated statement of operations equals comprehensive income.

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Oilfield Water Lines, LP

Notes to Consolidated Financial Statements (Continued)

3. Acquisitions

        On August 28, 2012, the Partnership acquired a 74% interest in OWL Pearsall SWD, LLC, a Limited Liability Company formed to own the operating assets, contracts and proprietary information of a water services business operating in South Texas.

        The fair values of the assets acquired are summarized below:

Saltwater disposal well

  $ 4,500,000  

Permits

    550,000  

Goodwill

    10,950,000  
       

Fair value of assets acquired

    16,000,000  

Non-controlling interest

    (4,160,000 )

Acquisition debt

    (3,760,000 )
       

Consideration paid

  $ 8,080,000  
       
       

        On August 28, 2012 the Partnership paid cash of $8,080,000 and had a fixed obligation to the sellers in the amount of $3,760,000. The Partnership also paid $203,986 in transaction costs associated with the acquisition.

        In December 2012, the fixed obligation of $3,760,000 was renegotiated, and the Partnership paid $8,510,000 to settle the obligation. The $4,750,000 difference between the liability recorded at the acquisition date and the amount ultimately paid to settle the liability is reported as "interest expense—non-controlling interest" in the Partnership's consolidated statement of operations. The Partnership also incurred and accrued $176,357 of interest expense related to this obligation, which is reported within "interest expense—related party" in the Partnership's consolidated statement of operations.

        Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entity and the Partnership and the acquired assembled workforce.

        On December 4, 2012, the Partnership purchased a 75% interest in OWL Karnes SWD, LLC, a Limited Liability Company formed to own the operating assets, contracts and proprietary information of a water services business operating in South Texas. The Partnership paid $7,500,000 cash for the ownership interest and paid $53,776 in transaction costs associated with the acquisition.

        The fair values of the assets acquired are summarized below:

Saltwater disposal well

  $ 5,500,000  

Permits

    550,000  

Real estate

    64,440  

Goodwill

    3,885,560  
       

Fair value of assets acquired

    10,000,000  

Non-controlling interest

    (2,500,000 )
       

Consideration paid

  $ 7,500,000  
       
       

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Oilfield Water Lines, LP

Notes to Consolidated Financial Statements (Continued)

3. Acquisitions (Continued)

        Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entity and the Partnership and the acquired assembled workforce.

        On December 27, 2012 the Partnership purchased all of the ownership interest in Lotus Oilfield Services, LLC, a company engaged in the wastewater hauling business, in South Texas for approximately $11,000,000 cash, inclusive of $1,500,000 of acquisition related debt. The Partnership paid $70,747 in transaction costs associated with the acquisition.

        The fair values of the assets acquired and liabilities assumed are summarized below:

Accounts receivable

  $ 2,903,540  

Property and equipment

    5,181,870  

Other current assets

    41,822  

Goodwill

    3,847,049  

Accounts payable

    (920,146 )

Other current liabilities

    (146,444 )
       

Fair value of net assets acquired

    10,907,691  

Note payable to related party (see Note 6)

    (1,500,000 )
       

Consideration paid

  $ 9,407,691  
       
       

        Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entity and the Partnership and the acquired assembled workforce.

Fair Value Methodology

        FASB ASC 805-20-30-1 "Business Combinations—Related Issues" states that "The acquirer shall measure the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree at their acquisition-date fair values." The determination of fair value in a business combination must be consistent with the definition of fair value and the fair value measurement principles described in FASB ASC 820 "Fair Value Measurement and Disclosures."

        Below is a discussion of the methodology the Partnership used to calculate the fair values for the identifiable assets acquired and liabilities assumed.

Saltwater Disposal Well and Property Plant and Equipment

        In arriving at the fair value, the Partnership utilized the cost approach using a replacement cost adjusted for various forms of depreciation.

Permits

        The Partnership utilized a market approach based on recent transactions in the Eagle Ford Shale.

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Oilfield Water Lines, LP

Notes to Consolidated Financial Statements (Continued)

3. Acquisitions (Continued)

Real Estate

        The Partnership valued real estate acquired using the market approach based on prior acquisitions on a per-acre basis.

Other Assets and Liabilities

        The remaining assets and liabilities acquired are short-term in nature and their carrying values represent fair values at acquisition date.

4. Property and Equipment

        Property and equipment at December 31, 2012 consist of the following:

 
  Estimated Life   Book Value  

Disposal wells

  2 - 30 years   $ 16,245,158  

Logistics equipment

  2 - 7 years     5,181,869  

Building, furniture and improvements

  2 - 30 years     532,546  

Software

  3 years     24,870  

Permits and bonds

        1,125,000  

Land

        545,862  
           

        23,655,305  

Accumulated depreciation

        (269,239 )
           

      $ 23,386,066  
           
           

5. Accrued Expenses

        Accrued expenses at December 31, 2012 consist of the following:

Accrued wages

  $ 165,065  

Accrued income taxes

    34,368  

Accrued acquisition costs

    139,854  

Other accrued expenses

    86,489  
       

Total accrued expenses

  $ 425,776  
       
       

6. Related Party Debt

        Related party debt at December 31, 2012 consisted of the following:

Related party note payable and interest

  $ 1,500,000  

Related party accrued interest payable

    176,357  
       

  $ 1,676,357  
       
       

        Related party debt is payable in installments through December 27, 2013. The note bears interest at a rate of 6% per annum.

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Oilfield Water Lines, LP

Notes to Consolidated Financial Statements (Continued)

7. Related Party Transactions

        The Partnership enters into transactions with related parties in the normal course of business. Related party balances result from transactions with related parties.

        During the period from inception (August 6, 2012) to December 31, 2012, the Partnership paid $574,000 to related parties for reimbursement of expenses paid by related parties, chemicals, equipment rental, disposal fees and other operating and miscellaneous costs. Sales to related parties totaled $268,000 for the period from inception (August 6, 2012) to December 31, 2012.

        On December 5, 2012, the Partnership paid $8,510,000 to satisfy acquisition debt of $3,760,000. Accordingly, a charge of $4,750,000 was recorded as additional interest expense on the consolidated statement of operations. This amount excludes $176,357 of accrued interest associated with the note payable to a related party as of December 31, 2012.

Management Agreement

        Included in the Partnership's Limited Partnership Agreement are provisions for a fee to be paid to its general partner for management expenses and overhead expenses. The fees are not to exceed $50,000 per month or 10% of distributable cash flow.

8. Commitments and Contingencies

Concentrations of Credit Risk

        Financial instruments which subject the Partnership to credit risk consist primarily of cash balances maintained in excess of federal depository insurance limits and trade receivables. All of the Partnership's non-interest bearing cash balances were fully insured at December 31, 2012 due to a temporary federal program in effect from December 31, 2010 through December 31, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts. Beginning in 2013, insurance coverage reverted to $250,000 per depositor at each financial institution, and the Partnership's cash balances may again exceed federally insured limits.

        The Partnership's customer base consists primarily of oil and natural gas producers. The Partnership does not require collateral on its trade receivables. For the year ended December 31, 2012, one customer accounted for 76% of total revenues. There were no other customers that amounted to 10% or more of total revenues.

        Trade accounts receivable are from companies within the oil and natural gas industry and, as such, the Partnership is exposed to normal industry credit risks. As of December 31, 2012, two customers constituted 20% and 14% of total accounts receivable, respectively. There were no other customers that amounted to 10% or more of total accounts receivable balance at December 31, 2012.

Risk and Uncertainties

        As an independent oilfield services contractor that provides hauling services to oil and natural gas companies in Texas, the Partnership's revenue, profitability, cash flows and future rate of growth are substantially dependent on its ability to (1) maintain adequate equipment utilization, (2) maintain adequate pricing for the services it provides, and (3) maintain a trained work force. Failure to do so could adversely affect the Partnership's financial position, results of operations, and cash flows.

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Oilfield Water Lines, LP

Notes to Consolidated Financial Statements (Continued)

8. Commitments and Contingencies (Continued)

        Because the Partnership's revenues are generated primarily from customers who are subject to the same factors generally impacting the oil and natural gas industry, the Partnership's operations are also susceptible to market volatility resulting from economic, cyclical, weather related, or other factors related to the industry. Changes in the level of operating and capital spending in the industry, decreases in oil and natural gas prices, or industry perception about future oil and natural gas prices could materially decrease the demand for the Partnership's services, adversely affecting its financial position, results of operations and cash flows.

Employment Agreement

        On December 27, 2012 the Partnership entered into an employment agreement with the president of its water hauling subsidiary. The agreement has a term of two years and is renewable for an additional year on its annual anniversary, without prior written notice of intent to cancel. Included in the agreement is a provision for monthly bonuses paid to the employee based on net profits of the subsidiary and net profits of water disposal subsidiaries.

Management Agreement

        Included in the Partnership's Limited Partnership Agreement dated August 31, 2012 are provisions for a fee to be paid to its general partner for management and overhead expenses. The fees are not to exceed $50,000 per month or 10% of distributable cash flow.

Litigation

        The Partnership is subject to various other claims and legal actions that arise in the ordinary course of business. Management does not believe that any of these claims and actions, individually or in the aggregate, will have a material adverse effect on the Partnership's business, financial condition, results of operations, or cash flows, although management cannot guarantee that a material adverse effect will not occur.

Capital Commitments

        On August 31, 2012, a Limited Liability Company in which the Partnership owns a 75% interest was formed for the purpose of developing a water disposal facility in South Texas. Included in the Limited Liability Company Agreement is a provision to provide a carried interest to a related party in the amount of 25% of the first $5,000,000 in return for services rendered and to be rendered in the drilling of the disposal well. On December 27, 2012, a Limited Liability Company in which the Partnership owns 75% was formed for the purpose of developing a water disposal facility in South Texas. Included in the Limited Liability Company Agreement is a provision to provide a carried interest to a related party in the amount of 25% of the first $5,000,000 in return for services rendered and to be rendered in the drilling of the disposal well.

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Oilfield Water Lines, LP

Notes to Consolidated Financial Statements (Continued)

9. Supplemental Cash Flow Information

 
  Period From
inception
(August 6,
2012) to
December 31,
2012
 

Cash paid for

       

Interest

  $ 17  

Supplemental schedule of non-cash investing and financing activities

   
 
 

Financing of insurance notes

  $ 248,714  

10. Subsequent Events

        On August 2, 2013, NGL Energy Partners LP acquired all of the operating subsidiaries of Oilfield Water Lines, LP for 2,463,287 common units and $168 million in cash, plus net working capital.

        The agreement with NGL Energy Partners LP includes a provision whereby the purchase price may be increased if certain performance targets are achieved. If the acquired assets generate Adjusted EBITDA, as defined in the agreement, in excess of $40 million on an annualized basis during any one of the six months following the acquisition, the purchase price will be increased by six times the amount by which this annualized target is exceeded. The maximum potential increase to the purchase price under this provision is $60 million.

        The Partnership has evaluated subsequent events through September 27, 2013, the date the financial statements were available for issuance.

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Independent Auditor's Report

The Partners'
High Roller Wells Pearsall SWD No.1, Ltd.
Center, Texas

        We have audited the accompanying financial statements of High Roller Wells Pearsall SWD No.1, Ltd. (the "Partnership"), which comprise the statements of operations, partners' capital and cash flows for the period from January 1, 2012 through August 28, 2012, and the related notes to the financial statements.

Management's Responsibility for the Financial Statements

        Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

        Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

        An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

        We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

        In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations of High Roller Wells Pearsall SWD No.1, Ltd. and its cash flows for the period from January 1, 2012 through August 28, 2012 in accordance with accounting principles generally accepted in the United States of America.

Basis of Presentation

        As discussed in Note 1, these financial statements reflect the results of operations of the Partnership through the date on which substantially all operating assets were contributed to a newly formed entity in preparation for sale. These financial statements are not intended to be indicative of the actual operations of the Partnership for a full year.

/s/ BDO USA, LLP
Dallas, Texas
September 27, 2013

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Table of Contents


High Roller Wells Pearsall SWD No. 1, Ltd.

Statement of Operations

 
  Period from
January 1,
2012
through
August 28,
2012
 

Revenues

       

Water disposal services

  $ 4,254,661  

Crude oil sales

    4,746,835  
       

Total revenues

    9,001,496  

Expenses

   
 
 

Well servicing

    3,566,967  

General and administrative

    571,058  

Depreciation and amortization

    242,846  
       

Total expenses

    4,380,871  

Operating income

   
4,620,625
 

Other Expense

   
 
 

Interest expense

    (11,514 )
       

Income before taxes

    4,609,111  

Income tax expense

   
(68,400

)
       

Net income

  $ 4,540,711  
       
       

   

The accompanying notes are an integral part of these financial statements.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Statement of Partners' Capital

 
  Partners'
Capital
 

Balance at December 31, 2011

  $ 1,698,645  

Contributions

    1,123,595  

Withdrawals

    (2,850,671 )

Net income

    4,540,711  
       

Balance at August 28, 2012

  $ 4,512,280  
       
       

   

The accompanying notes are an integral part of these financial statements.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Statement of Cash Flows

 
  Period from
January 1,
2012
through
August 28,
2012
 

Cash flows from operating activities

       

Net income

  $ 4,540,711  

Adjustments to reconcile net income to net cash provided by operating activities:

       

Depreciation and amortization expense

    242,846  

Changes in operating assets and liabilities:

       

Accounts receivable

    (1,092,314 )

Accounts receivable—related parties

    (268,597 )

Other current assets

    (23,924 )

Accounts payable—trade

    472,556  

Accounts payable—related parties

    (810,396 )

Accrued expenses

    657,805  
       

Net cash provided by operating activities

    3,718,687  
       

Cash flows from investing activities

       

Purchases of property and equipment

    (1,511,575 )
       

Net cash used in investing activities

    (1,511,575 )
       

Cash flows from financing activities

       

Partner Contributions

    1,123,595  

Partner Withdrawals

    (2,850,671 )
       

Net cash used in financing activities

    (1,727,076 )
       

Net increase in cash and cash equivalents

    480,036  

Cash and cash equivalents

   
 
 

Beginning of period

    78  
       

End of period

  $ 480,114  
       
       

   

The accompanying notes are an integral part of these financial statements.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Notes to Financial Statements

1. Organization and Nature of Operations

Formation Transactions

        High Roller Wells Pearsall SWD No. 1, Ltd. ("Partnership") is a Texas Limited Partnership formed on November 18, 2011. The Partnership had an initial capitalization of $287,891 representing the net assets of an existing business contributed to the partnership by its partners.

        The initial assets contributed to the Partnership are summarized as follows:

Tangible well equipment

  $ 538,315  

Intangible drilling costs

    809,985  
       

Total assets

    1,348,300  

Current liabilities

    1,060,509  
       

Net assets

  $ 287,791  
       
       

Basis of Presentation

        The financial statements have been prepared to report the results of operations of the Partnership through the date of acquisition by Oilfield Water Lines, LP (the "Acquirer"). Such financial statements, rather than complete financial statements, are presented because the primary operating assets were acquired by Oilfield Water Lines, LP and ceased to be operated by the Partnership. The financial statements presented are not representative of the actual operations of the Partnership for a full year.

Nature of Business

        The Partnership is engaged in the water services business, the assets of which include water treatment and disposal facilities. The Partnership generates revenues from the gathering, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recovered hydrocarbons.

2. Summary of Significant Accounting Policies

Estimates

        The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of the Partnership's revenues, expenses and costs. These estimates are based on management's knowledge of current events, historical experience, and various other assumptions that management believes are reasonable under the circumstances. Although management believes these estimates are reasonable, actual results could differ from those estimates.

Revenue Recognition

        The Partnership records revenues from crude oil sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. The Partnership records water disposal revenues at the time the service is performed, which is upon receipt of the wastewater at the disposal facilities.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Notes to Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

Depreciation and Amortization

        Depreciation and amortization in the statement of operations includes depreciation and amortization of the Partnership's property, plant and equipment.

Cash and Cash Equivalents

        Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of three months or less at the date of purchase.

Accounts Receivable and Concentration of Credit Risk

        The Partnership grants unsecured credit to customers under normal industry standards and terms and evaluates each customer's creditworthiness as well as general economic conditions. An allowance for doubtful accounts is established, if necessary, based on the Partnership's assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes.

Property, Plant and Equipment

        The Partnership records property, plant and equipment at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and maintenance and repairs are expensed as incurred. The Partnership computes depreciation expense using the straight-line method over the estimated useful lives of the assets, which ranges from three to thirty years.

Impairments

        In accordance with Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") Topic 360 "Property, Plant and Equipment" ("ASC 360"), long-lived assets, such as property, and equipment, are reviewed whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Partnership evaluated its asset group in accordance with ASC 360 which resulted in no impairment for the period from January 1, 2012 through August 28, 2012.

Environmental

        The Partnership is subject to extensive federal, state, and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the adverse environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a

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High Roller Wells Pearsall SWD No. 1, Ltd.

Notes to Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.

        The Partnership may be subject to removal and restoration costs upon retirement of its facilities. Management is currently unable to predict when, or if, these facilities will become obsolete and require restoration. Accordingly, no provision for this liability has been made in these financial statements as both the amount and timing of such potential future costs are indeterminable.

Income taxes

        The Partnership is not subject to federal income taxes; instead, the taxable earnings or losses of the Partnership are reported by the Partners' in their separate income tax returns. Accordingly, no provision for federal income taxes has been made in these financial statements. The Partnership is subject to the Texas margin tax, and a provision for this expense is included in the statement of operations.

        The Partnership recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Partnership has evaluated tax positions taken or expected to be taken in the course of preparing the Partnership's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Therefore, no tax expense, including any interest and penalties, was recorded in the current period. Tax years from inception of the Partnership remain open.

3. Related Party Transactions

        The Partnership enters into transactions with related parties in the normal course of conducting business.

        The Partnership pays royalties of 9% of crude oil sales and $0.05 per barrel of water disposal to one of its partners, the seller of the mineral rights. Total royalties paid during the period ended August 28, 2012 were $675,612.

        For the period ended August 28, 2012, the Partnership had sales totaling $70,439 to a related party. The Partnership paid $1,569,250 to related parties for reimbursement of Partnership expenses paid by related parties, chemicals, freight, equipment rental, disposal fees and other operating and miscellaneous costs.

        During the period ended August 28, 2012, the Partnership paid $15,000 per month to an affiliate for accounting and administrative support.

4. Commitments and Contingencies

Concentrations of Credit Risk

        Financial instruments which subject the Partnership to credit risk consist primarily of cash balances maintained in excess of federal depository insurance limits and trade receivables. All of the Partnership's non-interest bearing cash balances were fully insured at August 28, 2012 and December 31, 2011 due to a temporary federal program in effect from December 31, 2010 through

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High Roller Wells Pearsall SWD No. 1, Ltd.

Notes to Financial Statements (Continued)

4. Commitments and Contingencies (Continued)

December 28, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts.

        The Partnership's customer base consists primarily of multi-national and independent oil and natural gas producers. The Partnership does not require collateral on its trade receivables. For the period ended August 28, 2012, two customers accounted for 59% and 12% of total revenues, respectively. There were no other customers that amounted to 10% or more of total revenues for the period ended August 28, 2012.

Litigation

        The Partnership is subject to various other claims and legal actions that arise in the ordinary course of business. The Partnership does not believe that any of these claims and actions, separately or in the aggregate, will have a material adverse effect on the Partnership's business, financial condition, results of operations, or cash flows, although no guarantee can be made that a material adverse effect will not occur.

5. Subsequent Events

        On August 28, 2012, the Partnership contributed all assets, excluding cash and accounts receivable, and certain contracts and proprietary information, to a newly-formed limited liability company ("Newco"). Contemporaneously, the partners of the Partnership entered into a Purchase and Sale Agreement with Oilfield Water Lines, LP for the sale of 74% of the membership interests of Newco.

        The Partnership has evaluated all subsequent events through September 27, 2013, the date the financial statements were available for issuance.

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Independent Auditor's Report

The Partners
High Roller Wells Karnes SWD No.1, Ltd.
Center, Texas

        We have audited the accompanying financial statements of High Roller Wells Karnes SWD No.1, Ltd. (the "Partnership"), which comprise the statements of operations and partners' capital and cash flows for the period from inception (March 14, 2012) through December 4, 2012, and the related notes to the financial statements.

Management's Responsibility for the Financial Statements

        Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

        Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

        An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

        We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

        In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of High Roller Wells Karnes SWD No.1, Ltd. for the period from inception (March 14, 2012) through December 4, 2012 in accordance with accounting principles generally accepted in the United States of America.

Basis of Presentation

        As discussed in Note 1, these financial statements reflect the results of operations of the Partnership through the date on which substantially all operating assets were contributed to a newly formed entity in preparation for sale. These financial statements are not intended to be indicative of the actual operations of the Partnership for a full year.

/s/ BDO USA, LLP
Dallas, Texas
September 27, 2013

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High Roller Wells Karnes SWD No. 1, Ltd.

Statement of Operations and Partners' Capital

 
  Period from
inception
(March 14, 2012)
through
December 4,
2012
 

Revenues

       

Water disposal services

  $ 1,323,392  

Crude oil sales

    3,335,524  
       

Total revenues

    4,658,916  
       

Expenses

       

Well servicing

    2,323,408  

General and administrative

    221,367  

Depreciation

    301,148  
       

Total expenses

    2,845,923  
       

Operating income

    1,812,993  

Other Income (Expense)

   
 
 

Interest expense

    (18,468 )
       

Income before taxes

    1,794,525  
       

Provision for taxes

    (26,800 )
       

Net income

    1,767,725  

Partners' Capital, at inception

   
 

Capital Contributions

    5,400,000  
       

Partners' Capital, at December 4, 2012

  $ 7,167,725  
       
       

   

The accompanying notes are an integral part of these financial statements.

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High Roller Wells Karnes SWD No. 1, Ltd.

Statement of Cash Flows

 
  Period from
inception
(March 14, 2012)
through
December 4,
2012
 

Cash flows from operating activities

       

Net income

  $ 1,767,725  

Adjustments to reconcile net income to net cash provided by operating activities:

       

Depreciation

    301,148  

Changes in operating assets and liabilities:

       

Accounts receivable

    (438,377 )

Other current assets

    (4,640 )

Accounts payable

    288,504  

Accrued expenses

    298,500  
       

Net cash provided by operating activities

    2,212,860  
       

Cash flows from investing activities

       

Purchases of property and equipment

    (7,085,110 )
       

Net cash used in investing activities

    (7,085,110 )
       

Cash flows from financing activities

       

Partner contributions

    5,400,000  

Borrowings on debt—related party

    800,000  

Repayment of debt—related party

    (400,000 )
       

Net cash provided by financing activities

    5,800,000  
       

Net increase in cash and cash equivalents

    927,750  

Cash and cash equivalents, at inception

     
       

Cash and cash equivalents, at December 4, 2012

  $ 927,750  
       
       

   

The accompanying notes are an integral part of these financial statements.

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High Roller Wells Karnes SWD No. 1, Ltd.

Notes to Financial Statements

1. Organization and Nature of Operations

Formation Transactions

        High Roller Wells Karnes SWD No. 1, Ltd. (the "Partnership") is a Texas Limited Liability Company formed on March 14, 2012. The Partnership had an initial capitalization of $250,000 with partner commitments for additional contributions as needed for working capital. Additional capital contributions made through December 4, 2012 totaled $5,150,000.

Basis of Presentation

        As described in Note 6, Oilfield Water Lines, LP acquired a controlling interest in the Partnership on December 4, 2012. These financial statements have been prepared to report the results of operations of the Partnership through the date of acquisition by Oilfield Water Lines, LP (the "Acquirer"). Such financial statements, rather than complete financial statements, are presented because the primary operating assets were acquired by Oilfield Water Lines, LP and ceased to be operated by the Partnership. The financial statements presented are not representative of the actual operations of the Partnership for a full year.

Nature of Business

        The Partnership is engaged in the water services business, the assets of which include water treatment and disposal facilities. The Partnership generates revenues from the gathering, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recovered hydrocarbons.

2. Summary of Significant Accounting Policies

Estimates

        The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of the Partnership's revenues, expenses and costs. These estimates are based on management's knowledge of current events, historical experience, and various other assumptions that management believes to be reasonable under the circumstances. Although management believes these estimates are reasonable, actual results could differ from those estimates.

Revenue Recognition

        The Partnership records revenues from crude oil sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. The Partnership records water disposal revenues at the time the service is performed, which is upon receipt of the wastewater at the disposal facilities.

Depreciation

        Depreciation in the statement of operations includes all depreciation of property, plant and equipment. Property, plant and equipment consist primarily of water treatment and disposal facilities, which have an estimated useful life of 30 years.

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High Roller Wells Karnes SWD No. 1, Ltd.

Notes to Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

Cash and Cash Equivalents

        Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of three months or less at the date of purchase.

Impairments

        In accordance with Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") Topic 360 "Property, Plant and Equipment" ("ASC 360"), long-lived assets, such as property, and equipment, are reviewed whenever events or circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Partnership evaluated its asset group in accordance with ASC 360 which resulted in no impairment for the period from inception (March 14, 2012) through December 4, 2012.

Environmental

        The Partnership is subject to extensive federal, state, and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the adverse environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.

        The Partnership may be subject to removal and restoration costs upon retirement of its facilities. Management is currently unable to predict when, or if, these facilities will become obsolete and require restoration. Accordingly, no provision for this liability has been made in these financial statements as both the amount and timing of such potential future costs are indeterminable.

Income taxes

        The Partnership is not subject to federal income taxes; instead, the taxable earnings or losses of the Partnership are reported by the Partners' in their separate income tax returns. Accordingly, no provision for federal income taxes has been made in these financial statements. The Partnership is subject to the Texas margin tax, and a provision for this expense is included in the statements of operations.

        The Partnership recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Partnership has evaluated tax positions taken or expected to be taken in the course of preparing the Partnership's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax

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High Roller Wells Karnes SWD No. 1, Ltd.

Notes to Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Therefore, no tax expense, including any interest and penalties, was recorded in the current period. Tax years from inception of the Partnership remain open.

3. Long-Term Debt—Related Party

        On August 21, 2012, the Partnership executed a loan agreement with an entity owned by its partners whereby it borrowed a total of $800,000. The Partnership made principal payments on the note totaling $400,000 through December 4, 2012, leaving a principal balance of $400,000 at December 4, 2012. The note bore interest at a rate of 4% per with a maturity date of August 21, 2014. The note was subsequently paid in full on December 4, 2012.

4. Related Party Transactions

        The Partnership enters into transactions with related parties in the normal course of conducting business.

        The Partnership pays royalties of 9% of crude oil sales and $0.05 per barrel of water disposal to the related party land owner for disposal operations. Total royalties paid during the period ended December 4, 2012 were $411,566.

        Throughout 2012, the Partnership paid $15,000 per month to an affiliate for administrative support.

        During the period ended December 4, 2012, the Partnership paid approximately $257,000 for construction labor provided by an affiliate at the Partnership's well site.

        In 2012, the Partnership borrowed a total of $800,000 from an entity owned by its partners (see Note 3 above). Related party interest expense was $18,468 for the period ended December 4, 2012.

5. Commitments and Contingencies

Concentrations of Credit Risk

        Financial instruments which subject the Partnership to credit risk consist primarily of cash balances maintained in excess of federal depository insurance limits and trade receivables. All of the Partnership's non-interest bearing cash balances were fully insured at December 4, 2012 due to a temporary federal program in effect from December 31, 2010 through December 28, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts.

        The Partnership's customer base consists primarily of multi-national and independent oil and natural gas producers. The Partnership does not require collateral on its trade receivables. For the period ended December 4, 2012, one customer accounted for 72% of total revenues. There were no other customers that amounted to 10% or more of total revenues.

Litigation

        The Partnership is subject to various other claims and legal actions that arise in the ordinary course of business. Management does not believe that any of these claims and actions, separately or in the aggregate, will have a material adverse effect on the Partnership's business, financial condition,

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High Roller Wells Karnes SWD No. 1, Ltd.

Notes to Financial Statements (Continued)

5. Commitments and Contingencies (Continued)

results of operations, or cash flows, although no guarantee can be made that a material adverse effect will not occur.

6. Subsequent Events

        On December 4, 2012, the Partnership contributed all assets, excluding cash, accounts receivable, certain contracts and proprietary information, to a newly-formed limited liability company ("Newco"). Contemporaneously, the partners of the Partnership entered into a Purchase and Sale Agreement with Oilfield Water Lines, LP for the sale of 75% of the membership interests of Newco.

        The Partnership has evaluated subsequent events through September 27, 2013, the date the financial statements were available for issuance.

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Independent Auditor's Report

The Members
Lotus Oilfield Services, LLC
Alice, TX

        We have audited the accompanying financial statements of Lotus Oilfield Services, LLC (the "Company"), which comprise the statements of operations, changes in members' equity, and cash flows for the period from January 1, 2012 to December 27, 2012, and the related notes to the financial statements.

Management's Responsibility for the Financial Statements

        Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

        Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

        An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

        We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

        In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations of Lotus Oilfield Services, LLC and its cash flows for the period of January 1, 2012 to December 27, 2012 in accordance with accounting principles generally accepted in the United States of America.

Basis of Presentation

        As discussed in Note 1, these financial statements reflect the results of operations of the Company through the date on which all members' interests were sold.

/s/ BDO USA, LLP
Dallas, Texas
September 27, 2013

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Table of Contents


Lotus Oilfield Services, LLC

Statement of Operations

 
  Period from
January 1,
2012 to
December 27,
2012
 

Trucking revenues

  $ 8,402,100  

Expenses

   
 
 

Equipment expenses

    6,935,858  

General and administrative

    232,259  

Depreciation and amortization

    409,150  
       

Total expenses

    7,577,267  
       

Operating income

    824,833  

Other income (expense)

   
 
 

Interest expense

    (131,924 )

Other income, net

    13,643  
       

Income before income taxes

    706,552  

Provision for income taxes

    (35,900 )
       

Net income

  $ 670,652  
       
       

   

The accompanying notes are an integral part of these financial statements.

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Lotus Oilfield Services, LLC

Statement of Changes in Members' Equity

 
  Members'
Equity
  Retained
Earnings
  Total  

Balance at December 31, 2011

  $ 31,973   $ 500,314   $ 532,287  

Member contributions

    12,110         12,110  

Net income

        670,652     670,652  
               

Balance at December 27, 2012

  $ 44,083   $ 1,170,966   $ 1,215,049  
               
               

   

The accompanying notes are an integral part of these financial statements.

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Lotus Oilfield Services, LLC

Statement of Cash Flows

 
  Period from
January 1,
2012 to
December 27,
2012
 

Cash flows from operating activities

       

Net income

  $ 670,652  

Adjustments to reconcile net income to net cash provided by operating activities:

       

Depreciation and amortization expense

    409,150  

Gain on sale of equipment

    24,152  

Changes in operating assets and liabilities:

       

Accounts receivable

    (2,374,663 )

Accounts receivable—related parties

    (1,572 )

Prepaid expenses and other current assets

    6,428  

Accounts payable—trade

    646,322  

Accounts payable—related parties

    1,851,031  

Accrued expenses

    149,787  
       

Net cash provided by operating activities

    1,381,287  
       

Cash flows from investing activities

       

Purchases of property and equipment

    (4,314,725 )

Proceeds from sale of property and equipment

    65,404  
       

Net cash used in investing activities

    (4,249,321 )
       

Cash flows from financing activities

       

Borrowings on line of credit

    303,948  

Increase in equipment obligations

    2,583,565  

Partner contributions

    12,110  
       

Net cash provided by financing activities

    2,899,623  
       

Net increase in cash and cash equivalents

    31,589  

Cash and cash equivalents

       

Beginning of period

    60,720  
       

End of period

  $ 92,309  
       
       

   

The accompanying notes are an integral part of these financial statements.

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Lotus Oilfield Services, LLC

Notes to Financial Statements

1. Organization and Nature of Operations

Nature of Business

        Lotus Oilfield Services, LLC (the "Company") is an oilfield services contractor that provides fluid hauling services from well sites to reclamation and disposal sites. The Company's primary operating assets are tractors and trailers utilized in the hauling services business. The Company is a Texas Limited Liability Company formed April 19, 2010.

Basis of Presentation

        As described in Note 8, on December 27, 2012, the Company was acquired by OWL Lotus, LLC (the "Acquirer"). The financial statements have been prepared to report the results of operations of the Company through the date of acquisition by the Acquirer.

2. Risk and Uncertainties

        As an independent oilfield services contractor that provides hauling services to oil and natural gas companies in Texas, the Company's revenue, profitability, cash flows and future rate of growth are substantially dependent on the Company's ability to (1) maintain adequate equipment utilization, (2) maintain adequate pricing for the services the Company provides, and (3) maintain a trained work force. Failure to do so could adversely affect the Company's financial position, results of operations, and cash flows.

        Because the Company's revenues are generated primarily from customers who are subject to the same factors generally impacting the oil and natural gas industry, the Company's operations are also susceptible to market volatility resulting from economic, cyclical, weather related, or other factors related to such industry. Changes in the level of operating and capital spending in the industry, decreases in oil and natural gas prices, or industry perception about future oil and natural gas prices could materially decrease the demand for the Company's services, adversely affecting the Company's financial position, results of operations and cash flows.

3. Summary of Significant Accounting Policies

Use of Estimates

        The preparation of financial statements in accordance with generally accepted accounting principles in the United States ("GAAP") requires the Company to make estimates and assumptions that affect the reported amounts of the Company's revenues, expenses and costs. These estimates are based on the Company's knowledge of current events, historical experience, and various other assumptions that the Company believes to be reasonable under the circumstances.

        Critical estimates made in the preparation of the Company's financial statements include the collectability of accounts receivable, estimates of useful lives and recoverability of property, plant and equipment, and accruals for various commitments and contingencies, among others. Although the Company believes these estimates are reasonable, actual results could differ from those estimates.

Revenue Recognition

        The Company recognizes revenue upon completion of hauling services, provided collection of the relevant receivables is probable, persuasive evidence of an arrangement exists, and the price is fixed or

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Lotus Oilfield Services, LLC

Notes to Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

determinable. In accordance with Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 605-45 "Principal Agent Considerations" ("ASC 605-45") revenues are presented net of any sales taxes collected by Lotus Oilfield Services from its customers that are remitted to governmental authorities.

Cash and Cash Equivalents

        The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

        The Company grants unsecured credit to customers under normal industry standards and terms and evaluates each customer's creditworthiness as well as general economic conditions. An allowance for doubtful accounts is established, if necessary, based on the Company's assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes.

Property and Equipment

        Property and equipment are recorded at cost. Improvements or betterments that extend the useful life of the assets are capitalized. Expenditures for maintenance and repairs are charged to expense when incurred. The costs of assets retired or otherwise disposed of and the related accumulated depreciation are eliminated from the accounts in the period of disposal. Gains or losses resulting from property disposals are credited or charged to operations currently. Depreciation is recorded using the straight-line method over the estimated useful lives of the assets, which range from two to seven years.

Impairments

        In accordance with ASC Topic 360 "Property, Plant and Equipment" ("ASC 360"), long-lived assets, such as property, and equipment are reviewed whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Company evaluated its asset group in accordance with ASC 360 which resulted in no impairment for the period ended December 27, 2012.

Income taxes

        The Company is not subject to federal income taxes, rather the taxable earnings or losses of the Company are reported by the members in their separate income tax returns. Accordingly, no provision for federal income taxes has been made in these financial statements. The Company is subject to the Texas margin tax, an income tax, and a provision for this expense is included in the statement of operations.

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Lotus Oilfield Services, LLC

Notes to Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

        The Company recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Company has evaluated tax positions taken or expected to be taken in the course of preparing the Company's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Therefore, no tax expense, including any interest and penalties, was recorded in the current period. Tax years from inception of the Company remain open.

4. Equipment Notes Payable

        During the year ended December 31, 2011, the Company financed the purchase of certain vehicles and equipment through loans with commercial lenders. These loans were repayable in monthly installments with maturity dates through February 2016. Interest accrued at rate of 6% and was payable monthly. The loans were collateralized by equipment purchased with the proceeds of such loans and by second liens on accounts receivable. All notes were retired subsequent to December 27, 2012 in connection with the acquisition of the Company (see Note 8).

5. Related Party Transactions

        The Company enters into transactions with related parties in the normal course of conducting business.

        During the period ended December 27, 2012, the Company paid $1,164,000 to related parties for reimbursement of expenses paid by related parties, chemicals, equipment rental, disposal fees and other operating and miscellaneous costs. Sales to related parties totaled $360,167 for the period ended December 27, 2012.

        The Company borrowed funds from related parties during the period ended December 27, 2012. Interest accrued at rate of 6% and interest expense relating to these borrowings was $13,939 for the period ended December 27, 2012.

6. Commitments and Contingencies

Concentrations of Credit Risk

        Financial instruments which subject the Company to credit risk consist primarily of cash balances maintained in excess of federal depository insurance limits and trade receivables. All of the Company's non-interest bearing cash balances were fully insured at December 27, 2012 due to a temporary federal program in effect from December 31, 2010 through December 28, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts.

        The Company's customer base consists primarily of multi-national and independent oil and natural gas producers. The Company does not require collateral on its trade receivables. For the period ended December 27, 2012, two customers accounted for 14% and 11% of total revenues, respectively. There were no other customers that amounted to 10% or more of total revenues for the period ended December 27, 2012.

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Lotus Oilfield Services, LLC

Notes to Financial Statements (Continued)

6. Commitments and Contingencies (Continued)

Litigation

        The Company is subject to various other claims and legal actions that arise in the ordinary course of business. The Company does not believe that any of these claims and actions, separately or in the aggregate, will have a material adverse effect on the Company's business, financial condition, results of operations, or cash flows, although the Company cannot guarantee that a material adverse effect will not occur.

7. Supplemental Cash Flow Information

 
  Periods from
January 1,
2012 to
December 27,
2012
 

Cash paid for

       

Interest

  $ 57,312  

8. Subsequent Events

        On December 27, 2012, the Company was acquired by OWL Lotus, LLC. This acquisition has not been pushed down to the Company and these financial statements reflect no adjustments for acquisition accounting under ASC 805.

        On December 27, 2012, the Company entered into an employment agreement with its president. The agreement has a term of two years and is renewable for an additional year on its annual anniversary, without prior written notice of intent to cancel. Included in the agreement is a provision for monthly bonuses paid to the employee based on net profits of the Company and net profits of related party entities.

        The Company has evaluated subsequent events through September 27, 2013, the date the financial statements were available for issuance.

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Oilfield Water Lines, LP

Unaudited Condensed Consolidated Balance Sheets

 
  June 30,
2013
  December 31,
2012
 

Assets

             

Current assets

             

Cash and cash equivalents

  $ 1,143,664   $ 3,853,865  

Accounts receivable—trade

    7,143,976     3,834,236  

Prepaid expenses and other

    1,293,772     323,158  
           

Total current assets

    9,581,412     8,011,259  

Property and equipment, net

   
32,816,035
   
23,386,066
 

Goodwill

    18,681,334     18,682,609  

Receivables from affiliates

    72,573      

Other assets

    591,697     325,749  
           

Total assets

  $ 61,743,051   $ 50,405,683  
           
           

Liabilities and capital

             

Current liabilities

             

Accounts payable—trade

  $ 3,630,360   $ 4,333,007  

Book overdrafts

    655,653      

Insurance notes payable

        248,714  

Accrued expenses

    2,189,950     425,776  

Current portion of long-term debt

    1,046,953      

Related party debt

    1,880,016     1,676,357  
           

Total current liabilities

    9,402,932     6,683,854  
           

Long-term debt

    1,902,948      

Commitments and contingencies (Note 7)

   
 
   
 
 

Capital

   
 
   
 
 

General partner (0.1%)

    24,678     19,466  

Limited partners (99.9%)

    43,126,220     37,369,386  
           

Total partners' capital

    43,150,898     37,388,852  
           

Non-controlling interests

    7,286,273     6,332,977  

Total capital

   
50,437,171
   
43,721,829
 
           

Total liabilities and capital

  $ 61,743,051   $ 50,405,683  
           
           

   

The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.

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Oilfield Water Lines, LP

Unaudited Condensed Consolidated Statement of Operations

 
  Six Months
Ended
June 30, 2013
 

Revenues

       

Crude oil sales

  $ 12,590,048  

Water disposal services

    3,474,691  

Trucking revenue

    8,029,506  
       

Total revenues

    24,094,245  

Expenses

   
 
 

Well servicing

    11,920,178  

General and administrative

    2,983,318  

Loss on sale of assets

    13,902  

Depreciation

    1,296,590  
       

Total expenses

    16,213,988  

Operating income

   
7,880,257
 

Interest expense

   
(123,097

)
       

Income before income taxes

    7,757,160  

Provision for income taxes

   
(156,331

)
       

Net income

    7,600,829  
       

Net income attributable to non-controlling interest

    2,388,148  
       

Net income attributable to partners

  $ 5,212,681  
       
       

   

The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.

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Oilfield Water Lines, LP

Unaudited Condensed Consolidated Statement of Changes in Capital

 
  General
Partner
  Limited
Partners
  Non-
Controlling
Interest
  Total
Capital
 

Balance at December 31, 2012

  $ 19,466   $ 37,369,386   $ 6,332,977   $ 43,721,829  

Contributions

        3,673,943     514,040     4,187,983  

Distributions

        (3,124,578 )   (1,948,892 )   (5,073,470 )

Net income

    5,212     5,207,469     2,388,148     7,600,829  
                   

Balance at June 30, 2013

  $ 24,678   $ 43,126,220   $ 7,286,273   $ 50,437,171  
                   
                   

   

The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.

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Oilfield Water Lines, LP

Unaudited Condensed Consolidated Statement of Cash Flows

 
  Six Months
Ended
June 30, 2013
 

Cash flows from operating activities

       

Net income

  $ 7,600,829  

Adjustments to reconcile net loss to net cash provided by operating activities:

       

Depreciation expense

    1,296,590  

Provision for doubtful accounts

    258,000  

Changes in operating assets and liabilities:

       

Accounts receivable

    (3,567,740 )

Accounts receivable—affiliates

    (72,573 )

Prepaid expenses and other current assets

    (970,614 )

Other assets

    (265,948 )

Accounts payable—trade

    (702,647 )

Book overdrafts

    655,653  

Accrued expenses and other liabilities

    1,765,808  

Related party debt

    203,659  
       

Net cash provided by operating activities

    6,201,017  
       

Cash flows from investing activities

       

Purchases of property and equipment

    (10,726,919 )
       

Net cash used in investing activities

    (10,726,919 )
       

Cash flows from financing activities

       

Proceeds from borrowings

    2,949,902  

Payment of insurance note payable

    (248,714 )

Contributions from partners

    4,187,983  

Distributions to non-controlling interests

    (1,948,892 )

Withdrawals by partners

    (3,124,578 )
       

Net cash provided by financing activities

    1,815,701  
       

Net decrease in cash and cash equivalents

    (2,710,201 )

Cash and cash equivalents

   
 
 

Beginning of period

    3,853,865  
       

End of period

  $ 1,143,664  
       
       

   

The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.

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Table of Contents


Oilfield Water Lines, LP

Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization and Nature of Business

        Oilfield Water Lines, LP (the "Partnership") is a Texas Limited Partnership formed on August 6, 2012. The Partnership is engaged in the water services and hauling businesses, the assets of which primarily include water treatment and disposal facilities, trucks and trailers.

2. Summary of Significant Accounting Policies

Principles of Consolidation

        The Partnership's consolidated financial statements as of June 30, 2013 and for the six months then ended include the accounts of Oilfield Water Lines, LP and its controlled subsidiaries, which are HR OWL, LLC, OWL Operating, LLC, OWL Pearsall SWD, LLC, OWL Karnes SWD, LLC, OWL Cotulla SWD, LLC, OWL Nixon SWD, LLC, OWL Lotus, LLC and Lotus Oilfield Services, LLC. All significant intercompany balances and transactions have been eliminated in consolidation.

        The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim consolidated financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. The unaudited condensed consolidated financial statements include all adjustments that the Partnership considers necessary for a fair presentation of the financial position and results of operations for the interim period presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed consolidated financial statements do not include all the information and notes required by GAAP for complete annual consolidated financial statements. However, the Partnership believes that the disclosures made are adequate to make the information not misleading. These interim unaudited condensed consolidated financial statements should be read in conjunction with the audited financial statements of the Partnership for the period from inception (August 6, 2012) through December 31, 2012. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Use of Estimates

        The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of the Partnership's assets, liabilities, revenues, expenses and costs. These estimates are based on management's knowledge of current events, historical experience, and various other assumptions that it believes to be reasonable under the circumstances.

        Critical estimates management makes in the preparation of the Partnership's consolidated financial statements include the collectability of accounts receivable, estimates of useful lives and recoverability of property, plant and equipment, valuation of goodwill and accruals for various commitments and contingencies, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Revenue Recognition

        The Partnership generates revenues from the gathering, hauling, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recovered hydrocarbons.

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Oilfield Water Lines, LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

        The Partnership generally recognizes revenue when the customer takes ownership or assumes the risk of loss; collection of the relevant receivable is probable, persuasive evidence of arrangement exists; and the transaction price is fixed or determinable. Revenues are presented net of any sales taxes collected by the Partnership from its customers and remitted to taxing authorities.

        The Partnership records revenues from crude oil sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. The Partnership records water disposal revenues at the time the services are performed, which is upon receipt of the wastewater at the Partnership's disposal facilities.

        The Partnership recognizes revenue upon completion of hauling services, provided collection of the relevant receivables is probable, persuasive evidence of an arrangement exists, and the price is fixed or determinable.

Cash and Cash Equivalents

        The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

        The Partnership grants unsecured credit to customers under normal industry standards and terms and evaluates each customer's creditworthiness as well as general economic conditions. An allowance for doubtful accounts is established, if necessary, based on management's assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes. The allowance for doubtful accounts was $258,000 and $-0- at June 30, 2013 and December 31, 2012, respectively.

Property and Equipment

        Property and equipment are recorded at cost. Improvements or betterments that extend the useful life of the assets are capitalized. Expenditures for maintenance and repairs are charged to expense when incurred. The costs of assets retired or otherwise disposed of and the related accumulated depreciation are eliminated from the accounts in the period of disposal. Gains or losses resulting from property disposals are credited or charged to operations currently. Depreciation is recorded using the straight-line method over the estimated useful lives of the assets.

Goodwill

        Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Goodwill is not amortized, but instead the Partnership evaluates goodwill for impairment annually, or more often if events or circumstances indicate that the assets might be impaired.

Impairments of Long-Lived Assets

        In accordance with Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") Topic 360 "Property, Plant and Equipment", long-lived assets, such as property, and equipment, and finite-lived intangibles subject to amortization, are reviewed for impairment whenever events or circumstances indicate that the carrying amount of such assets may not be

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Table of Contents


Oilfield Water Lines, LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Partnership evaluated its asset group in accordance with ASC 360 for the six months ended June 30, 2013 and concluded that no impairment of long-lived assets existed.

Non-Controlling Interests

        The Partnership has four consolidated subsidiaries in which outside parties own interests. The Partnership's ownership interests in these subsidiaries range from 74% to 75%. The non-controlling interest shown in the Partnership's consolidated statement of operations represents the other owners' interests in these entities.

Environmental

        The Partnership is subject to extensive federal, state, and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the adverse environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.

        The Partnership may be subject to removal and restoration costs upon retirement of its facilities. Management is currently unable to predict when, or if, these facilities will become obsolete and require restoration. Accordingly, no provision for this liability has been made in these financial statements as both the amount and timing of such potential future costs are indeterminable.

Income Tax

        The Partnership is not subject to federal income taxes; instead, the taxable earnings or losses of the Partnership are reported by the Partners in their separate income tax returns. Accordingly, no provision for federal income taxes has been made in these financial statements. The Partnership is subject to the Texas margin tax, and a provision for this expense is included in the statement of operations.

        The Partnership recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Partnership has evaluated tax positions taken or expected to be taken in the course of preparing the Partnership's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Therefore, no tax expense, including any interest and penalties, was recorded in the current period. All tax years since inception of the Partnership (August 6, 2012) remain open.

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Table of Contents


Oilfield Water Lines, LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

Comprehensive Income

        Comprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Partnership has no items of comprehensive income other than net income in any period presented. Therefore, net income as presented in the consolidated statement of operations equals comprehensive income.

3. Property and Equipment

        Property and equipment consist of the following:

 
  Estimated
Life
  June 30,
2013
  December 31,
2012
 

Disposal wells

    2 - 30 years   $ 23,062,266   $ 16,245,158  

Logistics equipment

    2 - 7 years     8,825,550     5,181,869  

Building, furniture and improvements

    2 - 30 years     765,670     532,546  

Software

    3 years     24,870     24,870  

Permits and bonds

          1,125,000     1,125,000  

Land

          569,148     545,862  
                 

          34,372,504     23,655,305  

Accumulated depreciation

         
(1,556,469

)
 
(269,239

)
                 

        $ 32,816,035   $ 23,386,066  
                 
                 

4. Accrued Expenses

        Accrued expenses consist of the following:

 
  June 30,
2013
  December 31,
2012
 

Accrued wages

  $ 623,542   $ 165,065  

Accrued income taxes

    170,918     34,368  

Accrued acquisition costs

        139,854  

Other accrued expenses

    1,395,490     86,489  
           

Total accrued expenses

  $ 2,189,950   $ 425,776  
           
           

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Table of Contents


Oilfield Water Lines, LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

5. Related Party Debt

        Related party debt consisted of the following:

 
  June 30,
2013
  December 31,
2012
 

Related party note payable and interest

  $ 1,500,000   $ 1,500,000  

Related party accrued interest payable

    22,500     176,357  

Related party accounts payable

    357,516      
           

  $ 1,880,016   $ 1,676,357  
           
           

        Related party debt is payable in installments through December 27, 2013. The note bears interest at a rate of 6% per annum.

6. Related Party Transactions

        The Partnership enters into transactions with related parties in the normal course of business. Related party balances result from transactions with related parties.

        During the six months ended June 30, 2013, the Partnership paid $4,743,174 to related parties for reimbursement of expenses paid by related parties, chemicals, equipment rental, disposal fees and other operating and miscellaneous costs. Sales to related parties totaled $30,174 for the six months ended June 30, 2013.

Management Agreement

        Included in the Partnership's Limited Partnership Agreement are provisions for a fee to be paid to its general partner for management expenses and overhead expenses. The fees are not to exceed $50,000 per month, or 10% of distributable cash flow.

7. Commitments and Contingencies

Concentrations of Credit Risk

        Financial instruments which subject the Partnership to credit risk consist primarily of cash balances maintained in excess of federal depository insurance limits and trade receivables. All of the Partnership's non-interest bearing cash balances were fully insured at December 31, 2012 due to a temporary federal program in effect from December 31, 2010 through December 31, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts. Beginning 2013, insurance coverage reverted to $250,000 per depositor at each financial institution, and the Partnership's non-interest bearing cash balances may again exceed federally insured limits. The Partnership restricts investment of temporary cash investments to financial institutions with high credit standings.

        The Partnership's customer base consists primarily of multi-national and independent oil and natural gas producers. The Partnership does not require collateral on its trade receivables. For the six months ended June 30, 2013, three customers accounted for 29%, 22%, and 17% of total revenues, respectively. There were no other customers that amounted to 10% or more of total revenues.

        Trade accounts receivable are from companies within the oil and natural gas industry and as such the Partnership is exposed to normal industry credit risks. At June 30, 2013, one customer accounted

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Table of Contents


Oilfield Water Lines, LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

7. Commitments and Contingencies (Continued)

for 37% of total accounts receivable. As of December 31, 2012, two customers constituted 20% and 14% of total accounts receivable, respectively. There were no other customers that amounted to 10% or more of total accounts receivable balance at June 30, 2013 or December 31, 2012.

Risks and Uncertainties

        As an independent oilfield services contractor that provides hauling services to oil and natural gas companies in Texas, the Partnership's revenue, profitability, cash flows and future rate of growth are substantially dependent on its ability to (1) maintain adequate equipment utilization, (2) maintain adequate pricing for the services it provides, and (3) maintain a trained work force. Failure to do so could adversely affect the Partnership's financial position, results of operations, and cash flows.

        Because the Partnership's revenues are generated primarily from customers who are subject to the same factors generally impacting the oil and natural gas industry, the Partnership's operations are also susceptible to market volatility resulting from economic, cyclical, weather related, or other factors related to the industry. Changes in the level of operating and capital spending in the industry, decreases in oil and natural gas prices, or industry perception about future oil and natural gas prices could materially decrease the demand for the Partnership's services, adversely affecting its financial position, results of operations and cash flows.

Employment Agreement

        On December 27, 2012 the Partnership entered into an employment agreement with the president of its water hauling subsidiary. The agreement has a term of two years and is renewable for an additional year on its annual anniversary, without prior written notice of intent to cancel. Included in the agreement is a provision for monthly bonuses paid to the employee based on net profits of the subsidiary and net profits of water disposal subsidiaries.

Management Agreement

        Included in the Partnership's Limited Partnership Agreement dated August 31, 2012 are provisions for a fee to be paid to its general partner for management expenses and overhead expenses. The fees are not to exceed $50,000 per month or 10% of distributable cash flow.

Litigation

        The Partnership is subject to various other claims and legal actions that arise in the ordinary course of business. Management does not believe that any of these claims and actions, individually or in the aggregate, will have a material adverse effect on the Partnership's business, financial condition, results of operations, or cash flows, although management cannot guarantee that a material adverse effect will not occur.

Capital Commitments

        On August 31, 2012, a Limited Liability Company in which the Partnership owns a 75% interest was formed for the purpose of developing a water disposal facility in South Texas. Included in the Limited Liability Company Agreement is a provision to provide a carried interest to a related party in the amount of 25% of the first $5,000,000 in return for services rendered and to be rendered in the

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Oilfield Water Lines, LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

7. Commitments and Contingencies (Continued)

drilling of the disposal well. On December 27, 2012, a Limited Liability Company in which the Partnership owns 75% was formed for the purpose of developing a water disposal facility in South Texas. Included in the Limited Liability Company Agreement is a provision to provide a carried interest to a related party in the amount of 25% of the first $5,000,000 in return for services rendered and to be rendered in the drilling of the disposal well.

8. Supplemental Cash Flow Information

 
  Six Months
Ended
June 30, 2013
 

Cash paid for

       

Interest

  $ 78,098  

9. Subsequent Events

        On August 2, 2013, NGL Energy Partners LP acquired all of the operating subsidiaries of Oilfield Water Lines, LP for 2,463,287 common units and $168 million in cash, plus net working capital.

        The agreement with NGL Energy Partners LP includes a provision whereby the purchase price may be increased if certain performance targets are achieved. If the acquired assets generate Adjusted EBITDA, as defined in the agreement, in excess of $40 million on an annualized basis during any one of the six months following the acquisition, the purchase price will be increased by six times the amount by which this target is exceeded. The maximum potential increase to the purchase price under this provision is $60 million.

        The Partnership has evaluated subsequent events through October 17, 2013, the date the financial statements were available for issuance.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Unaudited Condensed Statement of Operations

 
  Six Months
Ended
June 30, 2012
 

Revenues

       

Water disposal services

  $ 3,177,552  

Crude oil sales

    3,703,352  
       

Total revenues

    6,880,904  

Expenses

   
 
 

Well servicing

    2,649,793  

General and administrative

    163,924  

Depreciation

    170,646  
       

Total expenses

    2,984,363  
       

Income before taxes

    3,896,541  

Income tax expense

   
(53,487

)
       

Net income

  $ 3,843,054  
       
       

   

The accompanying notes are an integral part of these unaudited condensed financial statements.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Unaudited Condensed Statement of Cash Flows

 
  Six Months
Ended
June 30, 2012
 

Cash flows from operating activities

       

Net income

  $ 3,843,054  

Adjustments to reconcile net income to net cash provided by operating activities:

       

Depreciation expense

    170,646  

Changes in operating assets and liabilities:

       

Accounts receivable

    (1,465,585 )

Accounts receivable—related parties

    (363,207 )

Other current assets

    (36,036 )

Accounts payable—trade

    503,776  

Accounts payable—related parties

    (548,399 )

Accrued expenses

    35,982  
       

Net cash provided by operating activities

    2,140,231  
       

Cash flows from investing activities

       

Purchases of property and equipment

    (1,384,559 )
       

Net cash used in investing activities

    (1,384,559 )
       

Cash flows from financing activities

       

Partner Contributions

    1,760,134  

Partner Withdrawals

    (2,183,014 )
       

Net cash used in financing activities

    (422,880 )
       

Net increase in cash and cash equivalents

    332,792  

Cash and cash equivalents

   
 
 

Beginning of period

    78  
       

End of period

  $ 332,870  
       
       

   

The accompanying notes are an integral part of these unaudited condensed financial statements.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Notes to Unaudited Condensed Financial Statements

1. Organization and Nature of Operations

Formation

        High Roller Wells Pearsall SWD No. 1, Ltd. ("Partnership") is a Texas Limited Partnership formed on November 18, 2011.

Basis of Presentation

        The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. The unaudited condensed financial statements include all adjustments that the Partnership considers necessary for a fair presentation of the financial position and results of operations for the interim period presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed financial statements do not include all the information and notes required by GAAP for complete annual financial statements. However, the Partnership believes that the disclosures made are adequate to make the information not misleading. These interim unaudited condensed financial statements should be read in conjunction with the audited financial statements of the Partnership for the period from January 1, 2012 through August 28, 2012. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Nature of Business

        The Partnership is engaged in the water services business, the assets of which include water treatment and disposal facilities. The Partnership generates revenues from the gathering, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recovered hydrocarbons.

2. Summary of Significant Accounting Policies

Estimates

        The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of the Partnership's revenues, expenses and costs. These estimates are based on management's knowledge of current events, historical experience, and various other assumptions that management believes to be reasonable under the circumstances. Although management believes these estimates are reasonable, actual results could differ from those estimates.

Revenue Recognition

        The Partnership records revenues from crude oil sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. The Partnership records disposal revenues at the time the service is performed, which is upon receipt of the wastewater at the disposal facilities.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Notes to Unaudited Condensed Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

Depreciation

        Depreciation in the statement of operations includes depreciation of the Partnership's property, plant and equipment.

Cash and Cash Equivalents

        Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of three months or less at the date of purchase.

Accounts Receivable and Concentration of Credit Risk

        The Partnership grants unsecured credit to customers under normal industry standards and terms and evaluates each customer's creditworthiness as well as general economic conditions. An allowance for doubtful accounts is established, if necessary, based on the Partnership's assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes. There was no allowance for doubtful accounts as of June 30, 2012.

Property, Plant and Equipment

        The Partnership records property, plant and equipment at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and maintenance and repairs are expensed as incurred. The Partnership computes depreciation expense using the straight-line method over the estimated useful lives of the assets, which ranges from three to thirty years.

Impairments

        In accordance with Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") Topic 360 "Property, Plant and Equipment" ("ASC 360"), long-lived assets, such as property, and equipment, are reviewed for impairment whenever events or circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Partnership evaluated its asset group in accordance with ASC 360 for the six months ended June 30, 2012 and concluded that no impairment of long-lived assets existed.

Environmental

        The Partnership is subject to extensive federal, state, and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the adverse environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Notes to Unaudited Condensed Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

        Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.

        The Partnership may be subject to removal and restoration costs upon retirement of its facilities. Management is currently unable to predict when, or if, these facilities will become obsolete and require restoration. Accordingly, no provision for this liability has been made in these financial statements as both the amount and timing of such potential future costs are indeterminable.

Income taxes

        The Partnership is not subject to federal income taxes, rather the taxable earnings or losses of the Partnership are reported by the Partners' in their separate income tax returns. Accordingly, no provision for federal income taxes has been made in these financial statements. The Partnership is subject to the Texas margin tax, and a provision for this expense is included in the statements of operations.

        The Partnership recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Partnership has evaluated tax positions taken or expected to be taken in the course of preparing the Partnership's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Therefore, no tax expense, including any interest and penalties, was recorded in the current period. Tax years from inception of the Partnership remain open.

3. Related Party Transactions

        The Partnership enters into transactions with related parties in the normal course of conducting business. Accounts payable-affiliates result from transactions with affiliates which the Partnership believes are at terms consistent with those available to third-party customers and from third-party vendors.

        The Partnership pays royalties of 9% of crude oil sales and $0.05 per barrel of water disposal to one of its partners, the seller of the mineral rights. Total royalties paid during the six months ended June 30, 2012 were $542,292.

        For the six months ended June 30, 2012, the Partnership had sales totaling $36,715 to a related party. The Partnership paid $648,975 to related parties for reimbursement of Partnership expenses paid by related parties, chemicals, freight, equipment rental, disposal fees and other operating and miscellaneous costs.

        During the six months ended June 30, 2012, the Partnership paid $15,000 per month to an affiliate for accounting and administrative support.

4. Commitments and Contingencies

Concentrations of Credit Risk

        Financial instruments which subject the Partnership to credit risk consist primarily of cash balances maintained in excess of federal depository insurance limits and trade receivables. All of the

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High Roller Wells Pearsall SWD No. 1, Ltd.

Notes to Unaudited Condensed Financial Statements (Continued)

4. Commitments and Contingencies (Continued)

Partnership's non-interest bearing cash balances were fully insured at June 30, 2012 due to a temporary federal program in effect from December 31, 2010 through December 28, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts.

        The Partnership's customer base consists primarily of multi-national and independent oil and natural gas producers. The Partnership does not require collateral on its trade receivables. For the six months ended June 30, 2012, three customers accounted for 28%, 14%, and 12% of total revenues, respectively. There were no other customers that amounted to 10% or more of total revenues for the six months ended June 30, 2012.

Litigation

        The Partnership is subject to various other claims and legal actions that arise in the ordinary course of business. The Partnership does not believe that any of these claims and actions, individually or in the aggregate, will have a material adverse effect on the Partnership's business, financial condition, results of operations, or cash flows, although no guarantee can be made that a material adverse effect will not occur.

5. Subsequent Events

        On August 28, 2012, the Partnership contributed all assets, excluding cash and accounts receivable, and certain contracts and proprietary information, to a newly-formed limited liability company ("Newco"). Contemporaneously, the partners of the Partnership entered into a Purchase and Sale Agreement with Oilfield Water Lines, LP for the sale of 74% of the membership interests of Newco.

        The Partnership has evaluated subsequent events through October 17, 2013, the date the financial statements were available for issuance.

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High Roller Wells Karnes SWD No. 1, Ltd.

Unaudited Condensed Statement of Operations

 
  Period from
inception
(March 14, 2012)
through
June 30,
2012
 

Revenues

       

Water disposal services

  $ 247,456  

Crude oil sales

    400,987  
       

Total revenues

    648,443  
       

Expenses

       

Well servicing

    482,800  

General and administrative

    61,978  

Depreciation

    64,010  
       

Total expenses

    608,788  
       

Operating income

    39,655  

Other income (expense)

   
 
 

Interest expense

    (274 )
       

Income before taxes

    39,381  
       

Provision for taxes

    (3,746 )
       

Net income

    35,635  
       

   

The accompanying notes are an integral part of these unaudited condensed financial statements.

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High Roller Wells Karnes SWD No. 1, Ltd.

Unaudited Condensed Statement of Cash Flows

 
  Period from
inception
(March 14,
2012) to
June 30,
2012
 

Cash flows from operating activities

       

Net income

  $ 35,635  

Adjustments to reconcile net income to net cash provided by operating activities:

       

Depreciation

    64,010  

Changes in operating assets and liabilities:

       

Accounts receivable

    (203,778 )

Accounts receivable—related party

    (279,661 )

Other current assets

    (99,923 )

Accounts payable

    889,757  

Accrued expenses

    90,196  
       

Net cash provided by operating activities

    496,236  
       

Cash flows from investing activities

       

Purchases of property and equipment

    (6,289,970 )
       

Net cash used in investing activities

    (6,289,970 )
       

Cash flows from financing activities

       

Partner contributions

    5,487,525  

Borrowings from related parties

    306,209  
       

Net cash provided by financing activities

    5,793,734  
       

Net increase in cash and cash equivalents

     

Cash and cash equivalents, at inception

   
 
       

Cash and cash equivalents, at June 30, 2012

  $  
       
       

   

The accompanying notes are an integral part of these unaudited condensed financial statements.

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1. Organization and Nature of Operations

Formation Transactions

        High Roller Wells Karnes SWD No. 1, Ltd. (the "Partnership") is a Texas Limited Liability Company formed on March 14, 2012.

Basis of Presentation

        The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. The unaudited condensed financial statements include all adjustments that the Partnership considers necessary for a fair presentation of the financial position and results of operations for the interim period presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed financial statements do not include all the information and notes required by GAAP for complete annual financial statements. However, the Partnership believes that the disclosures made are adequate to make the information not misleading. These interim unaudited condensed financial statements should be read in conjunction with the audited financial statements of the Partnership for the period from inception (March 14, 2012) through December 4, 2012. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Nature of Business

        The Partnership is engaged in the water services business, the assets of which include water treatment and disposal facilities. The Partnership generates revenues from the gathering, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recovered hydrocarbons.

2. Summary of Significant Accounting Policies

Estimates

        The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of the Partnership's revenues, expenses and costs. These estimates are based on management's knowledge of current events, historical experience, and various other assumptions that management believes to be reasonable under the circumstances. Although management believes these estimates are reasonable, actual results could differ from those estimates.

Revenue Recognition

        The Partnership records revenues from crude oil sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. The Partnership records water disposal revenues at the time the service is performed, which is upon receipt of the wastewater at the disposal facilities.

Depreciation

        Depreciation in the statement of operations includes all depreciation of property, plant and equipment. Property, plant and equipment consist primarily of water treatment and disposal facilities, which have an estimated useful life of 30 years.

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2. Summary of Significant Accounting Policies (Continued)

Cash and Cash Equivalents

        Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of three months or less at the date of purchase.

Impairments

        In accordance with Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") Topic 360 "Property, Plant and Equipment" ("ASC 360"), long-lived assets, such as property, and equipment, are reviewed for impairment whenever events or circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Partnership evaluated its asset group in accordance with ASC 360 for the period from inception (March 14, 2012) through June 30, 2012, and concluded that no impairment of long-lived assets existed.

Environmental

        The Partnership is subject to extensive federal, state, and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the adverse environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.

        The Partnership may be subject to removal and restoration costs upon retirement of its facilities. Management is currently unable to predict when, or if, these facilities will become obsolete and require restoration. Accordingly, no provision for this liability has been made in these financial statements as both the amount and timing of such potential future costs are indeterminable.

Income taxes

        The Partnership is not subject to federal income taxes, rather the taxable earnings or losses of the Partnership are reported by the Partners' in their separate income tax returns. Accordingly, no provision for federal income taxes has been made in these financial statements. The Partnership is subject to the Texas margin tax, and a provision for this expense is included in the statements of operations.

        The Partnership recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Partnership has evaluated tax positions taken or expected to be taken in the course of preparing the Partnership's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Therefore, no tax expense, including any interest and penalties, was recorded in the current period. Tax years from inception of the Partnership remain open.

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3. Related Party Transactions

        The Partnership enters into transactions with related parties in the normal course of conducting business which the Partnership believes are at terms consistent with those available to third-party customers and from third-party vendors.

        The Partnership pays royalties of 9% of crude oil sales and $0.05 per barrel of water disposal to the related party land owner for disposal operations. Total royalties paid during the period from inception (March 14, 2012) through June 30, 2012 were $49,064.

        Throughout 2012, the Partnership paid $15,000 per month to an affiliate for administrative support.

        During the period from inception (March 14, 2012) through June 30, 2012, the Partnership paid approximately $204,810 for construction labor provided by an affiliate at the Partnership's well site.

4. Commitments and Contingencies

Concentrations of Credit Risk

        Financial instruments which subject the Partnership to credit risk consist primarily of cash balances maintained in excess of federal depository insurance limits and trade receivables. All of the Partnership's non-interest bearing cash balances were fully insured at June 30, 2012 due to a temporary federal program in effect from December 31, 2010 through December 28, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts.

        The Partnership's customer base consists primarily of multi-national and independent oil and natural gas producers. The Partnership does not require collateral on its trade receivables. For the period from inception (March 14, 2012) through June 30, 2012, two customers accounted for 57% and 11% of total revenues, respectively. There were no other customers that amounted to 10% or more of total revenues.

Litigation

        The Partnership is subject to various other claims and legal actions that arise in the ordinary course of business. Management does not believe that any of these claims and actions, individually or in the aggregate, will have a material adverse effect on the Partnership's business, financial condition, results of operations, or cash flows, although no guarantee can be made that a material adverse effect will not occur.

5. Subsequent Events

        On December 4, 2012, the Partnership contributed all assets, excluding cash and accounts receivable, certain contracts and proprietary information, to a newly-formed limited liability company ("Newco"). Contemporaneously, the partners of the Partnership entered into a Purchase and Sale Agreement with Oilfield Water Lines, LP for the sale of 75% of the membership interests of Newco.

        The Partnership has evaluated subsequent events through October 17, 2013, the date the financial statements were available for issuance.

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Lotus Oilfield Services, LLC

Unaudited Condensed Statement of Operations

 
  Six Months
Ended
June 30,
2012
 

Trucking revenue

  $ 3,290,651  
       

Expenses

       

Equipment expenses

    2,822,587  

General and administrative

    63,059  

Depreciation

    118,325  
       

Total expenses

    3,003,971  
       

Operating income

    286,680  

Other income (expense)

   
 
 

Interest expense

    (49,626 )

Other income, net

    4,500  
       

Income before income taxes

    241,554  

Provision for income taxes

   
(18,057

)
       

Net income

  $ 223,497  
       
       

   

The accompanying notes are an integral part of these unaudited condensed financial statements.

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Lotus Oilfield Services, LLC

Unaudited Condensed Statement of Cash Flows

 
  Six Months
Ended
June 30,
2012
 

Cash flows from operating activities

       

Net income

  $ 223,497  

Adjustments to reconcile net income to net cash provided by operating activities:

       

Depreciation expense

    118,325  

Gain on sale of equipment

    (4,500 )

Changes in operating assets and liabilities:

       

Accounts receivable

    (614,454 )

Accounts receivable—related parties

    (72,491 )

Prepaid expenses and other current assets

    20,379  

Accounts payable—trade

    (119,485 )

Accounts payable—related parties

    338,770  

Accrued expenses

    124,077  
       

Net cash provided by operating activities

    14,118  
       

Cash flows from investing activities

       

Purchases of property and equipment

    (927,242 )

Proceeds from sale of property and equipment

    27,500  
       

Net cash used in investing activities

    (899,742 )
       

Cash flows from financing activities

       

Repayments on debt

    (222,866 )

Borrowings on line of credit

    200,000  

Borrowings on related party note

    (30,567 )

Increase in equipment obligations

    956,133  

Other

    (5,794 )
       

Net cash provided by financing activities

    896,906  
       

Net increase in cash and cash equivalents

    11,282  

Cash and cash equivalents

   
 
 

Beginning of period

    60,720  
       

End of period

  $ 72,002  
       
       

   

The accompanying notes are an integral part of these unaudited condensed financial statements.

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Lotus Oilfield Services, LLC

Notes to Unaudited Condensed Financial Statements

1. Organization and Nature of Operations

Nature of Business

        Lotus Oilfield Services, LLC (the "Company") is an oilfield services contractor that provides fluid hauling services from well sites to reclamation and disposal sites. The Company's primary operating assets are tractors and trailers utilized in the hauling services business. The Company is a Texas Limited Liability Company formed April 19, 2010.

Basis of Presentation

        The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. The unaudited condensed financial statements include all adjustments that the Company considers necessary for a fair presentation of the results of operations for the interim period presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed financial statements do not include all the information and notes required by GAAP for complete annual financial statements. However, the Company believes that the disclosures made are adequate to make the information not misleading. These interim unaudited condensed financial statements should be read in conjunction with the audited financial statements of the Company for the period from January 1, 2012 through December 27, 2012. The results of operations for an interim period are not necessarily indicative of the results to be expected for a full year.

2. Risk and Uncertainties

        As an independent oilfield services contractor that provides hauling services to oil and natural gas companies onshore in Texas, the Company's revenue, profitability, cash flows and future rate of growth are substantially dependent on the Company's ability to (1) maintain adequate equipment utilization, (2) maintain adequate pricing for the services the Company provides, and (3) maintain a trained work force. Failure to do so could adversely affect the Company's financial position, results of operations, and cash flows.

        Because the Company's revenues are generated primarily from customers who are subject to the same factors generally impacting the oil and natural gas industry, the Company's operations are also susceptible to market volatility resulting from economic, cyclical, weather related, or other factors related to such industry. Changes in the level of operating and capital spending in the industry, decreases in oil and natural gas prices, or industry perception about future oil and natural gas prices could materially decrease the demand for the Company's services, adversely affecting the Company's financial position, results of operations and cash flows.

3. Summary of Significant Accounting Policies

Use of Estimates

        The preparation of financial statements in accordance with generally accepted accounting principles in the United States ("GAAP") requires the Company to make estimates and assumptions that affect the reported amounts of the Company's assets, liabilities, revenues, expenses and costs. These estimates are based on the Company's knowledge of current events, historical experience, and various other assumptions that the Company believes to be reasonable under the circumstances.

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Lotus Oilfield Services, LLC

Notes to Unaudited Condensed Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

        Critical estimates made in the preparation of the Company's financial statements include the collectability of accounts receivable, estimates of useful lives and recoverability of property, plant and equipment, and accruals for various commitments and contingencies, among others. Although the Company believes these estimates are reasonable, actual results could differ from those estimates.

Revenue Recognition

        The Company recognizes revenue upon completion of hauling services, provided collection of the relevant receivables is probable, persuasive evidence of an arrangement exists, and the price is fixed or determinable. In accordance with Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 605-45 "Principal Agent Considerations" ("ASC 605-45") revenues are presented net of any sales taxes collected by Lotus Oilfield Services from its customers that are remitted to governmental authorities.

Cash and Cash Equivalents

        The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

        The Company grants unsecured credit to customers under normal industry standards and terms and evaluates each customer's creditworthiness as well as general economic conditions. An allowance for doubtful accounts is established, if necessary, based on the Company's assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes.

Property and Equipment

        Property and equipment are recorded at cost. Improvements or betterments that extend the useful life of the assets are capitalized. Expenditures for maintenance and repairs are charged to expense when incurred. The costs of assets retired or otherwise disposed of and the related accumulated depreciation are eliminated from the accounts in the period of disposal. Gains or losses resulting from property disposals are credited or charged to operations currently. Depreciation is recorded using the straight-line method over the estimated useful lives of the assets.

Impairments

        In accordance with ASC Topic 360 "Property, Plant and Equipment" ("ASC 360"), long-lived assets, such as property, and equipment are reviewed whenever events in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Company evaluated its asset group in accordance with ASC 360 for the six months ended June 30, 2012 and concluded that no impairment of long-lived assets existed.

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Lotus Oilfield Services, LLC

Notes to Unaudited Condensed Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

Income taxes

        The Company is not subject to federal income taxes, rather the taxable earnings or losses of the Company are reported by the members in their separate income tax returns. Accordingly, no provision for federal income taxes has been made in these financial statements. The Company is subject to the Texas margin tax, an income tax, and a provision for this expense is included in the statement of operations.

        The Company recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Company has evaluated tax positions taken or expected to be taken in the course of preparing the Company's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Therefore, no tax expense, including any interest and penalties, was recorded in the current period. Tax years from inception of the Company remain open.

4. Equipment Notes Payable

        During the year ended December 31, 2011, the Company financed the purchase of certain vehicles and equipment through commercial loans with commercial lenders. These loans were repayable in monthly installments with the maturity dates through February 2016. Interest accrued at rate of 6% and was payable monthly. The loans were collateralized by equipment purchased with the proceeds of such loans and by second liens on accounts receivable. All notes were retired subsequent to December 27, 2012 in connection with the acquisition of the Company (see note 8).

5. Related Party Transactions

        The Company enters into transactions with related parties in the normal course of conducting business. Accounts receivable-related parties and Accounts payable-related parties result from transactions with related parties which the Company believes are at terms consistent with those available to third-party customers and from third-party vendors.

        During the six months ended June 30, 2012, the Company paid $617,401 to related parties for reimbursement of expenses paid by related parties, chemicals, equipment rental, disposal fees and other operating and miscellaneous costs. Sales to related parties totaled $125,281 for the six months ended June 30, 2012.

        The Company borrowed funds from related parties during the six months ended June 30, 2012. Interest accrued at rate of 6% and interest expense relating to these borrowings was $6,400 for the six months ended June 30, 2012.

6. Commitments and Contingencies

Concentrations of Credit Risk

        Financial instruments which subject the Company to credit risk consist primarily of cash balances maintained in excess of federal depository insurance limits and trade receivables. All of the Company's non-interest bearing cash balances were fully insured at June 30, 2012 due to a temporary federal

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Lotus Oilfield Services, LLC

Notes to Unaudited Condensed Financial Statements (Continued)

6. Commitments and Contingencies (Continued)

program in effect from December 31, 2010 through December 28, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts.

        The Company's customer base consists primarily of multi-national and independent oil and natural gas producers. The Company does not require collateral on its trade receivables. For the six months ended June 30, 2012, two customers accounted for 24% and 17% of total revenues, respectively. There were no other customers that amounted to 10% or more of total revenues for the six months ended June 30, 2012.

Litigation

        The Company is subject to various other claims and legal actions that arise in the ordinary course of business. The Company does not believe that any of these claims and actions, individually or in the aggregate, will have a material adverse effect on the Company's business, financial condition, results of operations, or cash flows, although the Company cannot guarantee that a material adverse effect will not occur.

7. Supplemental Cash Flow Information

 
  Six Months
Ended
June 30, 2012
 

Cash paid for

       

Interest

  $ 40,614  

8. Subsequent Events

        On December 27, 2012, the Company was acquired by OWL Lotus, LLC. This acquisition has not been pushed down to the Company and these financial statements reflect no adjustments for acquisition accounting under ASC 805.

        On December 27, 2012, the Company entered into an employment agreement with its president. The agreement has a term of two years and is renewable for an additional year on its annual anniversary, without prior written notice of intent to cancel. Included in the agreement is a provision for monthly bonuses paid to the employee based on net profits of the Company and net profits of related party entities.

        The Company has evaluated subsequent events through October 17, 2013, the date the financial statements were available for issuance.

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Independent Auditors' Report

The Board of Managers
Gavilon Energy (The Energy Business Units of Gavilon, LLC):

        We have audited the accompanying combined financial statements of Gavilon Energy (The Energy Business Units of Gavilon, LLC) (the Company), which comprise the combined balance sheets as of December 31, 2012 and 2011, and the related combined statements of operations, comprehensive income (loss), equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and the related notes to the combined financial statements.

Management's Responsibility for the Combined Financial Statements

        Management is responsible for the preparation and fair presentation of these combined financial statements in accordance with U.S. generally accepted accounting principles; this responsibility includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of combined financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' Responsibility

        Our responsibility is to express an opinion on these combined financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the combined financial statements are free from material misstatement.

        An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the combined financial statements. The procedures selected depend on the auditors' judgment, including the assessment of the risks of material misstatement of the combined financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity's preparation and fair presentation of the combined financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the combined financial statements.

        We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

        In our opinion, the combined financial statements referred to above present fairly in all material respects, the financial position of Gavilon Energy (The Energy Business Units of Gavilon, LLC) as of December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2012 in accordance with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Omaha, Nebraska
June 24, 2013

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Combined Balance Sheets

December 31, 2012 and 2011

(Dollars in millions)

 
  2012   2011  

Assets

             

Current assets:

             

Cash

  $ 5.0     12.7  

Trade accounts receivable, less allowance for doubtful accounts of $1.0 and $0.6, respectively

    473.5     568.4  

Inventories

    969.4     923.1  

Derivative assets

    58.4     90.0  

Other current assets

    21.2     81.3  
           

Total current assets

    1,527.5     1,675.5  
           

Property, plant, and equipment:

             

Land and land improvements

    13.8     7.5  

Buildings

    0.6     0.6  

Machinery and equipment

    7.9     6.9  

Tanks and pipelines

    88.6     81.6  

Construction in progress

    1.4     5.0  
           

    112.3     101.6  

Less accumulated depreciation

    (6.9 )   (2.3 )
           

Net property, plant, and equipment

    105.4     99.3  

Goodwill

    33.0     33.0  

Intangible assets, net

    15.9     22.3  

Equity method investments

    73.6      

Other assets

    13.5     14.3  
           

Total assets

  $ 1,768.9     1,844.4  
           
           

Liabilities and Equity

             

Current liabilities:

             

Current portion of long term debt

  $ 10.4     4.5  

Accounts payable

    592.2     542.4  

Advances on sales

    8.9     7.4  

Derivative liabilities

    32.2     82.5  

Accrued expenses

    17.6     50.2  

Payable due to parent

    434.3     394.6  
           

Total current liabilities

    1,095.6     1,081.6  

Long-term debt

    29.7     37.0  

Other noncurrent liabilities

    0.3     0.3  
           

Total liabilities

    1,125.6     1,118.9  
           

Total equity:

             

Parent Company's equity investment

    530.2     464.9  

Retained earnings

    111.5     245.1  

Accumulated other comprehensive income

    1.6     15.5  
           

Total equity

    643.3     725.5  
           

Commitments and contingencies (notes 13 and 14)

             

Total liabilities and equity

  $ 1,768.9     1,844.4  
           
           

   

See accompanying notes to combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Combined Statements of Operations

Years ended December 31, 2012, 2011, and 2010

(Dollars in millions)

 
  2012   2011   2010  

Net sales

  $ 239.8     379.3     192.9  

Cost of goods sold

    193.2     151.2     81.8  
               

Gross profit

    46.6     228.1     111.1  

Selling, general, and administrative expenses

    49.6     62.9     30.3  

Corporate allocated expense

    50.2     27.9     23.0  

Depreciation and amortization

    6.9     6.6     6.2  
               

Operating income (loss)

    (60.1 )   130.7     51.6  

Interest expense, net

    44.3     37.6     19.8  
               

Income (loss) from continuing operations before income taxes

    (104.4 )   93.1     31.8  

Income tax expense

    0.2     1.6      
               

Income (loss) from continuing operations

    (104.6 )   91.5     31.8  

Net income (loss) from discontinued operations

    (29.0 )   (5.5 )   3.7  
               

Net income (loss)

  $ (133.6 )   86.0     35.5  
               
               

   

See accompanying notes to combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Combined Statements of Comprehensive Income (Loss)

Years ended December 31, 2012, 2011, and 2010

(Dollars in millions)

 
  2012   2011   2010  

Net income (loss)

  $ (133.6 )   86.0     35.5  

Other comprehensive income (loss):

                   

Foreign currency translation adjustments

    0.1          

Net gain (loss) on derivative instruments designated and qualifying as cash flow hedges

    (14.1 )   7.6     19.9  

Available-for-sale securities

    0.1     0.1     (0.2 )
               

Total comprehensive income (loss)

  $ (147.5 )   93.7     55.2  
               
               

   

See accompanying notes to combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Combined Statements of Equity

Years ended December 31, 2012 and 2011

(Dollars in millions)

 
  Parent
Company's
equity
investment
  Retained
earnings
  Accumulated
other
comprehensive
income (loss)
  Total
equity
 

Balance at December 31, 2009

  $ 410.4     123.6     (11.9 )   522.1  

Net income

        35.5         35.5  

Contributed capital

    89.0             89.0  

Other comprehensive income

            19.7     19.7  
                   

Balance at December 31, 2010

    499.4     159.1     7.8     666.3  

Net income

        86.0         86.0  

Return of capital

    (34.5 )           (34.5 )

Other comprehensive income

            7.7     7.7  
                   

Balance at December 31, 2011

    464.9     245.1     15.5     725.5  

Net loss

        (133.6 )       (133.6 )

Contributed capital

    65.3             65.3  

Other comprehensive loss

            (13.9 )   (13.9 )
                   

Balance at December 31, 2012

  $ 530.2     111.5     1.6     643.3  
                   
                   

   

See accompanying notes to combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Combined Statements of Cash Flows

Years ended December 31, 2012, 2011, and 2010

(Dollars in millions)

 
  2012   2011   2010  

Cash flows from operating activities:

                   

Net income (loss)

  $ (133.6 )   86.0     35.5  

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:

                   

Depreciation and amortization

    11.4     8.6     6.2  

Provision for bad debts

    0.9     (0.3 )   (0.1 )

Amortization of debt issue costs

    0.5     0.5      

Other items

    (1.0 )   0.1     (0.2 )

Changes in operating assets and liabilities, net of acquisitions:

                   

Accounts receivable

    93.9     (327.0 )   95.0  

Inventories

    (46.3 )   (632.0 )   148.7  

Other current assets

    60.1     (74.6 )   (3.2 )

Derivative assets and liabilities

    (32.8 )   21.4     (17.4 )

Accounts payable

    52.2     206.5     (67.4 )

Advances on sales

    1.5     7.0     (8.4 )

Other accrued liabilities

    (32.5 )   24.4     (4.9 )

Noncurrent assets and liabilities

    0.1     19.1     (25.7 )
               

Net cash provided by (used in) operating activities

    (25.6 )   (660.3 )   158.1  
               

Cash flows from investing activities:

                   

Acquisitions, less cash acquired

        (8.0 )    

Additions to property, plant, and equipment

    (12.1 )   (36.2 )   (62.1 )

Investment in equity method investments

    (73.6 )        
               

Net cash used in investing activities

    (85.7 )   (44.2 )   (62.1 )
               

Cash flows from financing activities:

                   

Issuance of long-term debt

    4.6     52.7      

Repayments of long-term debt

    (6.0 )   (11.2 )    

Debt issue costs

        (2.7 )   (1.3 )

Contribution (return of) capital

    65.3     (34.5 )   89.0  

Payable due to parent

    39.7     712.4     (177.8 )
               

Net cash provided by (used in) financing activities

    103.6     716.7     (90.1 )
               

Net change in cash and cash equivalents

    (7.7 )   12.2     5.9  

Cash and cash equivalents at beginning of year

    12.7     0.5     (5.4 )
               

Cash and cash equivalents at end of year

  $ 5.0     12.7     0.5  
               
               

Supplemental cash and noncash flow information:

                   

Noncash construction payable

  $     1.3     5.5  

Cash paid for interest

    2.5     2.5      

   

See accompanying notes to combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements

December 31, 2012 and 2011

(1) Business Description

        The accompanying combined financial statements include the accounts of all operations that comprise the energy operations of Gavilon, LLC (collectively, the Company). The Company operates the marketing, trading, and distribution of energy commodities. Gavilon, LLC is a wholly owned subsidiary of The Gavilon Group, LLC (The Gavilon Group). The Gavilon Group, LLC is in the process of restructuring Gavilon, LLC to ultimately acquire, own, and operate the energy operations, which are set forth in these combined financial statements. Historically, the business units comprising Gavilon, LLC have been consolidated with The Gavilon Group. Material related party activity is summarized in note 16. As part of the potential separation of the energy operations, The Gavilon Group expects to transfer substantially all of its energy business units to Gavilon, LLC and transfer out any non-energy related business units to another subsidiary of The Gavilon Group. In addition, the Company has completed several restructuring initiatives, which have impacted the energy business units. These business units have been included in discontinued operations in the accompanying combined statement of operations for all years presented (note 15).

(2) Basis of Presentation

        The accompanying combined financial statements include the energy business units of Gavilon, LLC. When the Company does not have a controlling interest, but exerts a significant influence over the entity, the Company applies the equity method of accounting. All significant intercompany balances and transactions have been eliminated.

(3) Summary of Significant Accounting Policies

(a)   Use of Estimates

        The preparation of the combined financial statements, in accordance with generally accepted accounting principles (GAAP) in the United States of America, requires management to make estimates and assumptions that affect the amounts reported in the combined financial statements and accompanying notes. The most significant estimates relate to the valuation of derivatives, inventories, and the useful lives of fixed assets.

        Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. The Company adjusts such estimates and assumptions when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ significantly from these estimates. Changes in those estimates resulting from continuing changes in the economic environment will be reflected in the combined financial statements in future periods.

(b)   Trade Accounts Receivable

        Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and economic data.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(3) Summary of Significant Accounting Policies (Continued)

(c)   Inventories

        The Company uses the lower of cost or market for inventories, except crude oil inventory designated in a fair value hedging relationship. Cost is determined using the weighted average cost method. The Company uses fair value for crude oil inventory designated in a fair value hedging relationship.

(d)   Equity Method Investments

        The investments in and the operating results of 50% or less-owned entities not required to be consolidated are included in the combined financial statements on the basis of the equity method of accounting.

(e)   Property, Plant, and Equipment

        The Company's accounting for property, plant, and equipment is to record asset additions at cost. The estimated useful lives of the respective classes of assets are as follows:

Land improvements

  15 years

Buildings and building improvements

  15 - 40 years

Machinery and equipment

  7 - 15 years

Tanks and pipeline

  5 - 40 years

        Long-lived assets, such as property, plant, and equipment, and purchased intangible assets are subject to amortization, and are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group be tested for possible impairment, the Company first compares undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values, and third-party independent appraisals, as considered necessary. There were no circumstances that indicated the carrying value of long-lived assets or intangible assets may not be recoverable during the year ended December 31, 2012 or 2011.

(f)    Goodwill

        Goodwill represents the excess of the aggregate purchase price of acquired businesses over the estimated fair value of the net assets acquired in business combinations. Goodwill is reviewed for impairment at least annually. Goodwill is initially assessed based on qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50%. If it is determined by this assessment that, more likely than not, goodwill is impaired, the first step of testing is to compare the fair value of the reporting unit with its carrying value (including goodwill). If the fair

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(3) Summary of Significant Accounting Policies (Continued)

value of the reporting unit is less than its carrying value, an indication of goodwill impairment exists for the reporting unit and the enterprise must perform step two of the impairment test (measurement). Under step two, an impairment loss is recognized for any excess of the carrying amount of the reporting unit's goodwill over the implied fair value of that goodwill. The implied fair value of goodwill is determined by allocating the fair value of the reporting unit in a manner similar to a purchase price allocation. The residual fair value after this allocation is the implied fair value of the reporting unit goodwill. Fair value of the reporting unit is determined using a discounted cash flow analysis. If the fair value of the reporting unit exceeds its carrying value, step two does not need to be performed. The Company performs its annual impairment review of goodwill at June 30 and when a triggering event occurs between annual impairment tests. For 2012, the Company performed a qualitative assessment of goodwill and determined that it is more likely than not that the fair values of its reporting units are greater than the carrying amounts. Accordingly, there were no impairments of goodwill for the year ended December 31, 2012 or 2011.

(g)   Derivatives

        The Company uses commodity futures, options, and forward purchase and sales contracts in the normal course of business. The Company also uses interest rate related derivative instruments to manage its exposure related to changes in interest rates on its variable rate debt instruments. These derivative instruments are recognized at fair value in the combined balance sheets and changes in the fair value of derivatives not accounted for as hedges are recognized in earnings. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income until the hedged item is recognized in earnings.

        For all hedging relationships, the Company formally documents the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the hedged item, the nature of the risk being hedged, how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method of measuring ineffectiveness. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting cash flows of hedged items. For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing hedge ineffectiveness are recognized in current earnings.

        The Company discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is designated as a hedging instrument because it is unlikely that a forecasted transaction will occur, or management determines that designation of the derivative as a hedging instrument is no longer appropriate.

        In all situations in which hedge accounting is discontinued and the derivative is retained, the Company continues to carry the derivative at its fair value on the balance sheet and recognizes any

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(3) Summary of Significant Accounting Policies (Continued)

subsequent changes in its fair value in earnings. When it is probable that a forecasted transaction will not occur, the Company discontinues hedge accounting and recognizes immediately in earnings gains and losses that were accumulated in other comprehensive income.

(h)   Fair Values of Financial Instruments

        Unless otherwise specified, the Company believes the carrying value of its financial instruments approximates their fair value.

(i)    Netting of Accounts

        Where derivatives and accounts receivable and payable are subject to a master netting agreement and the accounting criteria to offset are met, the Company presents these accounts on a net basis in the combined financial statements.

(j)    Revenue Recognition

        Revenue is recognized when title and risk of loss are transferred to customers upon delivery based on terms of sale and collectibility is reasonably assured. Changes in the fair value of commodity derivatives are recognized in earnings immediately. Sales related to trading activities are recorded net, and margins earned on such transactions are included as a component of net sales. Net sales and cost of goods sold, if reported on a gross basis for these activities, would be increased by $18,819.6 million, $17,300.9 million, and $10,165.4 million for the years ended December 31, 2012, 2011, and 2010, respectively.

(k)   Income Taxes

        As a limited liability company, the Company does not pay U.S. federal or state income taxes under the provisions of the Internal Revenue Code. However, the Company's Canadian operations are subject to tax in its local jurisdiction.

        The Company recognizes the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.

(l)    Debt Issuance Costs

        The Company incurred certain financing costs associated with debt issuance (note 10). These costs were capitalized and are being amortized to expense using the effective interest rate method.

(m)  Recently Issued Accounting Pronouncements

        In December 2011, the Financial Accounting Standards Board (FASB) issued ASU No. 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of financial

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(3) Summary of Significant Accounting Policies (Continued)

statements to understand the effect of those arrangements on its financial position, and to allow investors to better compare financial statements prepared under U.S. GAAP with financial statements prepared under International Financial Reporting Standards (IFRS). The new standards are effective for annual periods beginning January 1, 2013, and interim periods within those annual periods. Retrospective application is required. The Company will implement these required disclosures provisions as of January 1, 2013.

(4) Business Combination

        During 2011, the Company acquired the refined products rack marketing business from Plains All American Pipeline, LP (Plains All American Pipeline). The final purchase price was approximately $8.0 million.

        The following table summarizes the fair values of the assets acquired and liabilities assumed for Plains All American Pipeline (in millions). The fair value assigned is based upon the final valuation for those assets:

Intangible assets

  $ 1.3  

Property and equipment

    1.1  

Goodwill

    5.6  
       

Total cash consideration

  $ 8.0  
       
       

(5) Goodwill and Intangible Assets

        Goodwill represents the excess of the purchase price over the estimated fair value of the net tangible and intangible assets acquired. The Company's goodwill includes goodwill that was allocated by The Gavilon Group as part of the overall purchase price allocation for all legal entities acquired. Factors that contributed to a purchase price resulting in goodwill included the Company's favorable market position in profitable and growing markets, favorable logistics and asset network, and intellectual capital associated with the Company. Goodwill is fully tax deductible to the members.

        The fair value of identifiable intangible assets consist of customer relationships (7 year weighted average useful life) and contractual obligations. Identifiable intangible assets as of December 31, 2012 and 2011 are as follows (in millions):

 
  Gross carrying
amounts
  Accumulated
amortization
  Net  

December 31, 2012:

                   

Customer relationships

  $ 43.1     (27.3 )   15.8  

Contractual obligations

    7.5     (7.4 )   0.1  
               

Total

  $ 50.6     (34.7 )   15.9  
               
               

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(5) Goodwill and Intangible Assets (Continued)


 
  Gross carrying
amounts
  Accumulated
amortization
  Net  

December 31, 2011:

                   

Customer relationships

  $ 43.1     (21.1 )   22.0  

Contractual obligations

    7.5     (7.2 )   0.3  
               

Total

  $ 50.6     (28.3 )   22.3  
               
               

        Aggregate amortization expense for amortizing intangible assets was $6.9 million, $6.3 million, and $6.2 million for the years ended December 31, 2012, 2011, and 2010 respectively. Estimated amortization expense for the next five years is $6.4 million in 2013, $6.2 million in 2014, $3.1 million in 2015, $0.1 million in 2016, and $0.1 million in 2017.

(6) Derivatives and Hedging Activities

        The Company purchases and sells commodities, such as gas, ethanol, natural gas, biodiesel and crude oil. The Company generally follows a policy of using commodity derivatives to minimize its net position of commodity inventories and forward cash purchase and sales contracts. The Company will also use commodity derivatives as components of market strategies designed to enhance margins. The results of these strategies can be significantly impacted by factors such as the volatility of the relationship between the value of commodity derivatives and the cash prices of the underlying commodities, counterparty contract defaults, and volatility of transportation markets.

        Changes in the fair value of commodity derivatives are recognized in earnings immediately, except for certain energy contracts and interest rate swaps that have been designated in a cash flow hedging relationship. The Company reports the fair value of its derivative assets and liabilities, including derivatives used in hedging relationships, on the combined balance sheets, as commodity and other contracts at fair value.

        For risk management purposes, the Company utilizes fair value hedges, cash flow hedges, and economic hedges. In addition to the use of derivative instruments to manage commodity price risk, the Company also enters into certain commodity derivative instruments for trading purposes. The majority of the Company's purchase and sales contracts qualify as derivative instruments and the change in fair value is reported in net sales and cost of sales in the accompanying combined statements of operations.

        For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or initially reported as a component of accumulated other comprehensive income and then recorded in income in the period or periods during which the hedged forecasted transaction affects income.

        The Company's policy is to report gains and losses associated with derivatives as follows:

Contract/derivative nature
  Line item
Commodities   Net sales
Interest rate swap   Interest expense

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(6) Derivatives and Hedging Activities (Continued)

        While a majority of the Company's use of derivative instruments is to manage market risks by economically hedging the Company's inventory and forward purchase and sales commitments, the Company also designates cash flow hedges. The Company has designated cash flow hedges associated with the future purchase and sales of natural gas anticipated for the period from January 2013 to February 2013. The object of the Company's cash flow hedges is to fix the price of natural gas purchase and sales at existing market prices that the Company deems favorable.

        The Company entered into an interest rate swap agreement to manage the variability of cash flows over certain portions of the interest payments related to the variable rate on the term loan (note 10). The interest rate swap agreement used by the Company has been recorded at fair value in the combined balance sheets with changes in fair value recorded in accumulated other comprehensive income. This amount is subsequently reclassified into interest expense as a yield adjustment of the hedged interest payments in the same period in which the related interest affects earnings. Amounts subsequently reclassified into interest expense during the year were immaterial, and no ineffectiveness was recognized during 2012, 2011, or 2010.

        As of December 31, 2012 and 2011, the fair value of the Company's interest rate swap agreement designated in a cash flow hedging relationship was an unrealized loss of $1.8 million. As of December 31, 2012 and 2011, the fair value of the Company's natural gas futures designated in a cash flow hedging relationship was $3.3 million and $17.4 million, respectively.

        The following table provides information about the gain or loss recognized in income and other comprehensive income (loss) on the Company's cash flow hedging derivative instruments for the years ended December 31, 2012, 2011, and 2010 (in thousands). Also, the information presents the notional volume of outstanding cash flow hedge derivative contracts by type of instrument.

Cash Flow Hedges

 
  Gain (loss)
recognized
in AOCI on
derivatives
(effective
portion)
   
   
   
   
 
 
  Gain (loss) reclassified from AOCI
into income (effective portion)
  Gain (loss) recognized in income on
derivatives (ineffective portion)
 
 
   
  2012 Amount    
  2012 Amount  
Commodity type
  2012 Amount   Location   Location  

Natural gas

  $ 4,540   Net sales   $ 18,646   Net sales   $  

Interest rate swaps

    767   Interest expense     (778 ) Interest expense      

 

Commodity type
  2011 Amount   Location   2011 Amount   Location   2011 Amount  

Natural gas

  $ 6,654   Net sales   $ (2,716 ) Net sales   $  

Interest rate swaps

    (804 ) Interest expense     (979 ) Interest expense      

 

Commodity type
  2010 Amount   Location   2010 Amount   Location   2010 Amount  

Natural gas

  $ 7,995   Net sales   $ (11,905 ) Net sales   $  

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(6) Derivatives and Hedging Activities (Continued)


Derivative instrument
  Notional contract
volumes (as of
December 31, 2012)
  Notional contract
volumes (as of
December 31, 2011)
  Notional contract
volumes (as of
December 31, 2010)
 

Natural gas futures (MMBtu's)

    931     930     (25,340 )

Interest rate swaps (millions of $)

    36     41      

        The following table summarizes the Company's outstanding interest rate swap agreement as of December 31, 2012:

Term
  Notional
amount
  Fixed
rate
  Variable
rate
 

1/24/11 - 3/31/18

  36 million     2.393     0.311  

        The following table summarizes the Company's outstanding interest rate swap agreement as of December 31, 2011:

Term
  Notional
amount
  Fixed
rate
  Variable
rate
 

1/24/11 - 3/31/18

  41 million     2.393     0.579  

        The Company did not exclude any components of the derivatives instruments' gains or losses from the assessment of hedge effectiveness for its cash flow hedging relationships. The Company expects that all of the unrealized gains (losses) as of December 31, 2012 on the natural gas cash flow hedging relationships will be reclassified into net sales over the next two months as a result of the hedged transaction affecting earnings. The deferred gains (losses) as of December 31, 2012 on the interest rate cash flow hedging relationships will be classified into interest expense over the term of the outstanding debt instruments (note 10).

        The Company has designated fair value hedges used to hedge certain crude oil inventories. The following table provides information about the gain or loss recognized in income on the Company's fair value hedging derivative instruments for the year ended December 31, 2012, 2011, and 2010 (in thousands). Also, the information presents the notional volume (in thousands) of outstanding derivative contracts designated in the fair value hedging relationships at December 31, 2012, 2011, and 2010.

Fair Value Hedges

 
  Gain (loss) recognized in
income on derivatives
  Gain (loss) recognized in
income on hedged item
  Gain (loss) recognized in
income on derivatives
(ineffective portion)
 
Commodity type
  Location   2012 Amount   Location   2012 Amount   Location   2012 Amount  

Crude oil inventory

  Net sales   $ (10,899 ) Net sales   $ 13,815   Net sales   $ 2,916  

 

Commodity type
  Location   2011 Amount   Location   2011 Amount   Location   2011 Amount  

Crude oil inventory

  Net sales   $ 2,388   Net sales   $ (1,574 ) Net sales   $ 814  

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(6) Derivatives and Hedging Activities (Continued)

Commodity type
  Location   2010 Amount   Location   2010 Amount   Location   2010 Amount  

Crude oil inventory

  Net sales   $ (244 ) Net sales   $ (10,143 ) Net sales   $ (10,387 )

 

Derivative instrument
  Notional contract
volumes (as of
December 31, 2012)
  Notional contract
volumes (as of
December 31, 2011)
  Notional contract
volumes (as of
December 31, 2010)
 

Crude oil futures (barrels)

    9,661     7,321     3,211  

        The following table summarizes the Company's notional volumes for their economic and trading derivative financial instruments as of December 31, 2012 and 2011 (amounts in thousands) by type of instrument:

 
  Exchange-
traded
   
   
 
 
  Non-exchange
traded
 
 
  Net
(short) long
 
2012
  (Short)   Long  

Natural gas (MMBtu's):

                   

Futures

    (4,700 )        

Options

             

Swaps

    (7,238 )       78  

Forwards

        (6,551 )    

Oil (barrels):

                   

Futures

    (3,262 )        

Options

    35          

Forwards

        (2,112 )   2,396  

 

 
  Exchange-
traded
   
   
 
 
  Non-exchange
traded
 
 
  Net
(short) long
 
2011
  (Short)   Long  

Natural gas (MMBtu's):

                   

Futures

    (8,730 )        

Options

    2,123          

Swaps

    (4,928 )   (536 )   1,052  

Forwards

        (7,267 )    

Oil (barrels):

                   

Futures

    (6,598 )        

Forwards

        (26,052 )   37,990  

        The Company has established guidelines, controls, and limits to manage and mitigate credit risk within risk tolerances established by the Company's Risk Committee. In addition, the Company has a credit committee that includes senior executives who meet on a regular basis to review the Company's credit activities and monitor compliance with the policies adopted by the Company. The Company attempts to mitigate its credit exposure by setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(6) Derivatives and Hedging Activities (Continued)

with less creditworthy counterparties through prepayments, letters of credit, and other security agreements, such as inventory, property, or other tangible assets. The use of master netting agreements is driven by industry practice, and anticipated volumes and complexity of the business relationship with the counterparty. The Company assumes credit and performance risk associated with commodity derivative contracts within the energy and agriculture industries; however, no counterparty was greater than 10% of the Company's net exposure.

        The Company has policies that limit the dollar risk exposure for each of its businesses. The Company also monitors the amount of associated counterparty credit risk for all nonexchange-traded transactions. The Company's trading activities are limited in terms of maximum dollar exposure, as measured by a value-at-risk methodology, and monitored to ensure compliance.

        As of December 31, 2012, the Company held certain derivative contracts with settlement dates through March 2016. However, approximately 95% of the Company's notional amount of commodity derivative contracts has settlement dates of less than one year. The Company also has interest rate swaps with settlement dates through March 2018.

(7) Equity Method Investments

        The Company's equity method investment in Glass Mountain Pipeline of $73.6 million at December 31, 2012 relates to a 50% interest in a development-stage limited liability company formed in May 2012. This investment includes the buyout of one of the original investors on October 9, 2012. The Company paid $52.3 for an additional 25% interest. Glass Mountain pipeline's operations consist of construction of an intrastate crude oil common carrier pipeline system in Oklahoma. Glass Mountain's total assets as of December 31, 2012 are $86.2 million and primarily represent cash and construction in progress. Glass Mountain's total liabilities as of December 31, 2012 are $0.1 million and primarily represent construction-related payables.

(8) Inventories

        The major classes of inventories at December 31, 2012 and 2011 are as follows (in millions):

 
  2012   2011  

Crude oil inventories carried at fair value

  $ 873.3     721.7  

Inventories carried at lower of cost or market:

   
 
   
 
 

Crude oil

    6.8     13.9  

Natural gas

    31.2     53.0  

Fuels

    57.6     126.0  

Other

    0.5     8.5  
           

  $ 969.4     923.1  
           
           

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(9) Fair Value Measurements

        Financial assets and liabilities carried at fair value will be classified and disclosed in one of the following three categories:

        Exchange-traded futures and options contracts are valued based on unadjusted quoted prices in active markets and are classified within Level 1. The Company's forward commodity purchase and sale contracts are classified as a Level 2 measurement. The Company estimates fair values based on exchange quoted prices, adjusted as appropriate for differences in local markets. These differences are generally valued using inputs from broker or dealer quotations, or market transactions in either the listed or over-the-counter (OTC) markets. The determination of the fair values also factor the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit, and priority interests), and also the impact of the Company's nonperformance risk on its liabilities.

        The Company also utilizes a midmarket pricing convention (the midpoint price between bid and ask prices) for valuing a significant portion of its assets and liabilities measured and reported at fair value. The Company is able to classify fair value balances based on the observability of inputs.

        The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2012 and 2011. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels.

 
  December 31, 2012  
 
  Level 1   Level 2   Level 3   Nettings   Total  

Assets (in millions):

                               

Inventory

  $ 873.3                 873.3  

Derivative assets

    13.1     2,930.1         (2,884.8 )   58.4  

Liabilities (in millions):

   
 
   
 
   
 
   
 
   
 
 

Derivative liabilities

  $     2,917.0         (2,884.8 )   32.2  

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(9) Fair Value Measurements (Continued)


 
  December 31, 2011  
 
  Level 1   Level 2   Level 3   Nettings   Total  

Assets (in millions):

                               

Inventory

  $ 721.7                 721.7  

Derivative assets

    28.7     4,583.7         (4,522.4 )   90.0  

Liabilities (in millions):

   
 
   
 
   
 
   
 
   
 
 

Derivative liabilities

  $     4,604.9         (4,522.4 )   82.5  

(10) Long-Term Debt

        Long-term obligations are as follows (in millions):

 
  2012   2011  

Term loan, variable interest rate, 5.74% and 6.16% at December 31, 2012 and 2011, respectively. 

  $ 40.1     41.5  
           

    40.1     41.5  

Less current portion

    (10.4 )   (4.5 )
           

Total long-term debt

  $ 29.7     37.0  
           
           

        During 2011, the Company issued $52.7 million in term loans to finance the construction of the crude oil tank farm. The term loan bears interest at the one-month LIBOR until December 31, 2012 and then three-month LIBOR thereafter and requires annual debt service payments beginning in March 2012 with the balance due December 2019. The term loans include an excess cash sweep provision that requires the Company to make additional principal payments if operating cash flows exceed a certain threshold. The Company has fixed this interest through the use of interest rate swaps for an effective interest rate of 7.05%.

        Principal Maturities—Principal maturities of long-term debt at December 31, 2012 are as follows (in millions):

2013

  $ 10.4  

2014

    5.3  

2015

    5.5  

2016

    5.8  

2017

    6.0  

Thereafter

    7.1  

        The term loan contains various restrictive covenants including a debt service coverage ratio. The term loan also provides for a first security interest in the property, plant, and equipment of the Company. The Company was in compliance with all financial debt covenants as of December 31, 2012 and 2011.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(11) Accumulated Other Comprehensive Loss

        The following table summarizes the balances of accumulated other comprehensive income (in millions):

 
  December 31  
 
  2012   2011  

Cash flow hedging derivatives

  $ 1.5     15.6  

Available-for-sale securities

        (0.1 )

Currency translation adjustment

    0.1      
           

  $ 1.6     15.5  
           
           

(12) Income Taxes

        As a limited liability company, the Company does not pay U.S. federal or state income taxes under the provisions of the Internal Revenue Code. However, the Company operates a wholly owned foreign subsidiary located in Canada. The tax consequences for these operations are reported on an accrual basis at the statutory rate of the respective jurisdictions.

        The components of the Company's income tax provision for the years ended December 31, 2012 and 2011 are as follows (in millions):

 
  2012   2011  

Pretax income—subject to Canadian tax

  $ 0.6     5.9  

Provision for income taxes:

             

Current

  $ 0.3     1.6  

Deferred

    (0.1 )    
           

  $ 0.2     1.6  
           
           

(13) Leases and Other Commitments

        Lease expense under operating leases and other commitment expenses totaled $6.4 million, $6.5 million, and $3.8 million for the years ended December 31, 2012, 2011, and 2010, respectively. The following is a summary (in millions) of operating leases consisting of rail, land and building, and other

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(13) Leases and Other Commitments (Continued)

commitments as of December 31, 2012. Other commitments primarily consist of obligations for storage of natural gas, crude and other fuels:

 
  Leases   Other
commitments
 

2013

  $ 5.4     49.0  

2014

    3.3     42.3  

2015

    2.4     39.3  

2016

    2.2     16.7  

2017

    1.5     7.5  

Later years

    1.5     3.5  
           

  $ 16.3     158.3  
           
           

(14) Contingencies

        The Company is party to a number of claims arising out of the operation of its business. Management records charges for probable losses that can be estimated. After taking into account liabilities recorded for all of the foregoing matters, management believes the ultimate resolution of such matters should not have a material adverse effect on the Company's combined financial position, results of operations, or liquidity. Costs of legal services are recognized in earnings as services are provided.

(15) Discontinued Operations

        During 2012, the Company completed restructuring initiatives that eliminated the operations of the Import/Export Ethanol, Glycerin, and weather and portfolio trading business units. Additionally, during 2012, the Company's management approved a plan to sell the Thackerville Propane Terminal. These operations are classified as held for sale and included in discontinued operations.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(15) Discontinued Operations (Continued)

        These business lines meet the criteria for being reported as discontinued operations and has been segregated from continuing operations. The following table summarizes the results from discontinued operations (in millions):

 
  Net sales   Net
income (loss)
 

2012:

             

Import/export ethanol

  $ (14.2 )   (20.2 )

Glycerin

    11.7     (6.1 )

Thackerville propane terminal

    0.1     (0.2 )

Weather and portfolio trading

    (1.7 )   (2.5 )
           

Total

  $ (4.1 )   (29.0 )
           
           

2011:

             

Import/export ethanol

  $ 2.4     (1.2 )

Glycerin

    10.7     (2.7 )

Thackerville propane terminal

        (0.2 )

Weather and portfolio trading

    (0.7 )   (1.4 )
           

Total

  $ 12.4     (5.5 )
           
           

2010:

             

Import/export ethanol

  $      

Glycerin

    12.7     2.0  

Weather and portfolio trading

    2.0     1.7  
           

Total

  $ 14.7     3.7  
           
           

(16) Related-Party Transactions

        The Gavilon Group provides a variety of services to the Company, such as information technology, treasury and cash management, payroll and human resources, legal, tax, facilities, general accounting and other corporate functions. Where possible, The Gavilon Group directly allocates costs to the Company based on usage or other direct allocation methods. Direct allocations to the Company are generally related to information technology, risk management, human resources, business development, compliance and facilities. The direct allocations are included in corporate allocations in the accompanying combined statement of operations, and were $7.8 million, $5.9 million and $5.1 million for the years ended December 31, 2012, 2011, and 2010, respectively.

        In addition to direct allocations from The Gavilon Group, indirect corporate expenses are allocated to the Company. These expenses are allocated to the Company based on historical company policy and may not be reflective of actual expenses incurred by the Company on a stand-alone basis. Indirect allocations charged to the Company are related to corporate departments such as executive, corporate finance and treasury, legal, communications, and stock-based compensation and were $43.5 million, $23.1 million, and $18.3 million for the years ended December 31, 2012, 2011, and 2010, respectively, and included in corporate allocated expense in the accompanying combined statements of

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(16) Related-Party Transactions (Continued)

operations. For the years ended December 31, 2012, 2011, and 2010, stock-based compensation expense included in the indirect allocations was $23.9 million, $13.5 million, and $11.0 million, respectively.

        The Gavilon Group also allocates corporate interest expense to the Company based on total invested and trade working capital utilized by the business and may not be reflective of interest expense incurred on a standalone basis. Interest expense allocated by The Gavilon Group to the Company was $39.3 million, $29.6 million, and $16.2 million for the years ended December 31, 2012, 2011, and 2010, respectively, and is included in the accompanying combined statement of operations.

        The amounts due to (from) The Gavilon Group are classified as payable due to (from) parent in current liabilities within the accompanying combined balance sheet and reflects the net cash transferred between the Companies for operating capital requirements, which includes corporate expense and interest allocations.

(17) Subsequent Event

        The Company received $29.3 million in January 2013 for a blender's tax credit from the federal government for blending biodiesel sold during 2012. This has been recognized in net sales during fiscal 2013 consistent with the enactment of the tax rule change.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Unaudited Condensed Combined Balance Sheets

September 30, 2013 and December 31, 2012

(Dollars in millions)

 
  September 30,
2013
  December 31,
2012
 

Assets

 

Current assets:

             

Cash

  $ 206.4     5.0  

Trade accounts receivable, less allowance for doubtful accounts of $0.7 and $1.0, respectively

    439.3     473.5  

Inventories

    176.5     969.4  

Derivative assets

    45.9     58.4  

Other current assets

    12.9     21.2  
           

Total current assets

    881.0     1,527.5  
           

Property, plant, and equipment:

             

Land and land improvements

    13.8     13.8  

Buildings

    0.6     0.6  

Machinery and equipment

    24.8     7.9  

Tanks and pipelines

    88.7     88.6  

Construction in progress

    7.1     1.4  
           

    135.0     112.3  

Less accumulated depreciation

    (19.0 )   (6.9 )
           

Net property, plant, and equipment

    116.0     105.4  

Goodwill

    33.0     33.0  

Intangible assets, net

    11.0     15.9  

Equity method investments

    100.1     73.6  

Other assets

    12.9     13.5  
           

Total assets

  $ 1,154.0     1,768.9  
           
           

Liabilities and Equity

 

Current liabilities:

             

Current portion of long term debt

  $     10.4  

Accounts payable

    415.3     592.2  

Advances on sales

    6.4     8.9  

Derivative liabilities

    12.2     32.2  

Accrued expenses

    24.8     17.6  

Payable due to parent

        434.3  
           

Total current liabilities

    458.7     1,095.6  

Long-term debt

        29.7  

Other noncurrent liabilities

    2.1     0.3  
           

Total liabilities

    460.8     1,125.6  
           

Total equity:

             

Parent Company's equity investment

    592.6     530.2  

Retained earnings

    99.3     111.5  

Accumulated other comprehensive income

    1.3     1.6  
           

Total equity

    693.2     643.3  
           

Commitments and contingencies (note 11)

             

Total liabilities and equity

  $ 1,154.0     1,768.9  
           
           

   

See accompanying notes to unaudited condensed combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Unaudited Condensed Combined Statements of Operations

Nine months ended September 30, 2013 and 2012

(Dollars in millions)

 
  Nine months
ended
September 30,
 
 
  2013   2012  

Net sales

  $ 224.4     196.3  

Cost of goods sold

    158.4     168.2  
           

Gross profit

    66.0     28.1  

Selling, general, and administrative expenses

    48.9     65.3  
           

Operating income (loss)

    17.1     (37.2 )

Interest expense, net

    27.5     39.8  
           

Loss from continuing operations before income taxes

    (10.4 )   (77.0 )

Income tax expense

        (0.2 )
           

Loss from continuing operations

    (10.4 )   (77.2 )

Net loss from discontinued operations

    (1.8 )   (24.1 )
           

Net loss

  $ (12.2 )   (101.3 )
           
           

   

See accompanying notes to unaudited condensed combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Unaudited Condensed Combined Statements of Comprehensive Loss

Nine months ended September 30, 2013 and 2012

(Dollars in millions)

 
  Nine months
ended
September 30,
 
 
  2013   2012  

Net loss

  $ (12.2 )   (101.3 )

Other comprehensive income (loss):

             

Foreign currency translation adjustments

        0.2  

Net loss on derivative instruments designated and qualifying as cash flow hedges

    (0.2 )   (18.3 )

Available-for-sale securities

    (0.1 )    
           

Total comprehensive loss

  $ (12.5 )   (119.4 )
           
           

   

See accompanying notes to unaudited condensed combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Unaudited Condensed Combined Statement of Equity

Nine months ended September 30, 2013

(Dollars in millions)

 
  Parent
Company's
equity
investment
  Retained
earnings
  Accumulated
other
comprehensive
income
  Total
equity
 

Balance at December 31, 2012

  $ 530.2     111.5     1.6     643.3  

Net loss

        (12.2 )       (12.2 )

Contributed capital

    62.4             62.4  

Other comprehensive loss

            (0.3 )   (0.3 )
                   

Balance at September 30, 2013

  $ 592.6     99.3     1.3     693.2  
                   
                   

   

See accompanying notes to unaudited condensed combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Unaudited Condensed Combined Statements of Cash Flows

Nine months ended September 30, 2013 and 2012

(Dollars in millions)

 
  Nine months ended
September 30,
 
 
  2013   2012  

Cash flows from operating activities:

             

Net loss

  $ (12.2 )   (101.3 )

Adjustments to reconcile net loss to net cash provided by (used in) operating activities:

             

Depreciation and amortization

    9.0     8.3  

Provision for bad debts

    0.3     0.3  

Amortization of debt issue costs

    1.7     0.4  

Other items

    2.8     (0.4 )

Changes in operating assets and liabilities:

             

Accounts receivable

    33.9     (286.0 )

Inventories

    793.0     320.0  

Other current assets

    12.6     46.3  

Derivative assets and liabilities

    (7.7 )   (30.4 )

Accounts payable

    (177.4 )   48.0  

Advances on sales

    (2.4 )   9.0  

Other accrued liabilities

    7.2     (32.0 )

Noncurrent assets and liabilities

    (1.0 )   0.3  
           

Net cash provided by operating activities

    659.8     (17.5 )
           

Cash flows from investing activities:

             

Additions to property, plant, and equipment

    (4.9 )   (10.7 )

Investment in equity method investments

    (26.5 )   (15.7 )
           

Net cash used in investing activities

    (31.4 )   (26.4 )
           

Cash flows from financing activities:

             

Issuance of long-term debt

        4.6  

Repayments of long-term debt

    (40.1 )   (3.4 )

Debt issue costs

    (5.8 )    

Contribution (return of) capital

    53.2     (41.8 )

Payable due to parent

    (434.3 )   82.7  
           

Net cash provided by (used in) financing activities

    (427.0 )   42.1  
           

Net change in cash and cash equivalents

    201.4     (1.8 )

Cash and cash equivalents at beginning of year

    5.0     12.7  
           

Cash and cash equivalents at end of year

  $ 206.4     10.9  
           
           

Supplemental cash and noncash flow information:

             

Cash paid for interest

  $ 1.1     1.9  

Contribution of property, plant, and equipment from parent

    9.2      

   

See accompanying notes to unaudited condensed combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(1) Business Description

        The accompanying combined financial statements include the accounts of all operations that comprise the energy operations of Gavilon, LLC (collectively, the Company). The Company operates the marketing, trading, and distribution of energy commodities. Gavilon, LLC was a wholly owned subsidiary of The Gavilon Group, LLC (The Gavilon Group). During 2013, the Gavilon Group, LLC restructured Gavilon, LLC to acquire, own, and operate the energy operations, which are set forth in these combined financial statements. Historically, the business units comprising Gavilon, LLC have been consolidated with The Gavilon Group. Material related party activity is summarized in note 13. As part of the separation of the energy operations, The Gavilon Group transferred substantially all of its energy business units to Gavilon, LLC and transferred out any non-energy related business units to another subsidiary of The Gavilon Group. In addition, the Company has completed several restructuring initiatives, which have impacted the energy business units. These business units have been included in discontinued operations in the accompanying combined statements of operations for all periods presented (note 12).

(2) Basis of Presentation

        The accompanying combined financial statements include the energy business units of Gavilon, LLC. When the Company does not have a controlling interest, but exerts a significant influence over the entity, the Company applies the equity method of accounting. All significant intercompany balances and transactions have been eliminated.

        The accompanying unaudited condensed combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim combined financial information and in accordance with the rules and regulations of the Securities and Exchange Commission (SEC). The unaudited condensed combined financial statements include all adjustments that the Company considers necessary for a fair presentation of the financial position and results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed combined financial statements do not include all the information and notes required by GAAP for complete annual combined financial statements. However, the Company believes that the disclosures made are adequate to make the information not misleading. These interim unaudited condensed combined financial statements should be read in conjunction with the Company's audited combined financial statements for the year ended December 31, 2012. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

(3) Summary of Significant Accounting Policies

(a)   Use of Estimates

        The preparation of the combined financial statements, in accordance with generally accepted accounting principles (GAAP) in the United States of America, requires management to make estimates and assumptions that affect the amounts reported in the combined financial statements and accompanying notes. The most significant estimates relate to the valuation of derivatives, inventories, and the useful lives of fixed assets.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(3) Summary of Significant Accounting Policies (Continued)

        Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. The Company adjusts such estimates and assumptions when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ significantly from these estimates. Changes in those estimates resulting from continuing changes in the economic environment will be reflected in the combined financial statements in future periods.

(b)   Trade Accounts Receivable

        Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and economic data.

(c)   Inventories

        The Company uses the lower of cost or market for inventories, except crude oil inventory designated in a fair value hedging relationship. Cost is determined using the weighted average cost method. The Company uses fair value for crude oil inventory designated in a fair value hedging relationship.

(d)   Equity Method Investments

        The investments in and the operating results of 50% or less-owned entities not required to be consolidated are included in the combined financial statements on the basis of the equity method of accounting.

(e)   Property, Plant, and Equipment

        The Company's accounting for property, plant, and equipment is to record asset additions at cost. The estimated useful lives of the respective classes of assets are as follows:

Land improvements

  15 years

Buildings and building improvements

  15 - 40 years

Machinery and equipment

  7 - 15 years

Tanks and pipeline

  5 - 40 years

        Long-lived assets, such as property, plant, and equipment, and purchased intangible assets are subject to amortization, and are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group be tested for possible impairment, the Company first compares undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(3) Summary of Significant Accounting Policies (Continued)

flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values, and third-party independent appraisals, as considered necessary. There were no circumstances that indicated the carrying value of long-lived assets or intangible assets may not be recoverable during the nine months ended September 30, 2013 or 2012.

(f)    Goodwill

        Goodwill represents the excess of the aggregate purchase price of acquired businesses over the estimated fair value of the net assets acquired in business combinations. Goodwill is reviewed for impairment at least annually. Goodwill is initially assessed based on qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50%. If it is determined by this assessment that, more likely than not, goodwill is impaired, the first step of testing is to compare the fair value of the reporting unit with its carrying value (including goodwill). If the fair value of the reporting unit is less than its carrying value, an indication of goodwill impairment exists for the reporting unit and the enterprise must perform step two of the impairment test (measurement). Under step two, an impairment loss is recognized for any excess of the carrying amount of the reporting unit's goodwill over the implied fair value of that goodwill. The implied fair value of goodwill is determined by allocating the fair value of the reporting unit in a manner similar to a purchase price allocation. The residual fair value after this allocation is the implied fair value of the reporting unit goodwill. Fair value of the reporting unit is determined using a discounted cash flow analysis. If the fair value of the reporting unit exceeds its carrying value, step two does not need to be performed. The Company performs its annual impairment review of goodwill at June 30 and when a triggering event occurs between annual impairment tests. For 2013 and 2012, the Company performed a qualitative assessment of goodwill and determined that it is more likely than not that the fair values of its reporting units are greater than the carrying amounts. Accordingly, there were no impairments of goodwill for the nine months ended September 30, 2013 or 2012.

(g)   Derivatives

        The Company uses commodity futures, options, and forward purchase and sales contracts in the normal course of business. The Company also uses interest rate related derivative instruments to manage its exposure related to changes in interest rates on its variable rate debt instruments. These derivative instruments are recognized at fair value in the combined balance sheets and changes in the fair value of derivatives not accounted for as hedges are recognized in earnings. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income until the hedged item is recognized in earnings.

        For all hedging relationships, the Company formally documents the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the hedged

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(3) Summary of Significant Accounting Policies (Continued)

item, the nature of the risk being hedged, how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method of measuring ineffectiveness. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting cash flows of hedged items. For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing hedge ineffectiveness are recognized in current earnings.

        The Company discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is designated as a hedging instrument because it is unlikely that a forecasted transaction will occur, or management determines that designation of the derivative as a hedging instrument is no longer appropriate.

        In all situations in which hedge accounting is discontinued and the derivative is retained, the Company continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings. When it is probable that a forecasted transaction will not occur, the Company discontinues hedge accounting and recognizes immediately in earnings gains and losses that were accumulated in other comprehensive income.

(h)   Fair Values of Financial Instruments

        Unless otherwise specified, the Company believes the carrying value of its financial instruments approximates their fair value.

(i)    Netting of Accounts

        Where derivatives and accounts receivable and payable are subject to a master netting agreement and the accounting criteria to offset are met, the Company presents these accounts on a net basis in the combined financial statements.

(j)    Revenue Recognition

        Revenue is recognized when title and risk of loss are transferred to customers upon delivery based on terms of sale and collectibility is reasonably assured. Changes in the fair value of commodity derivatives are recognized in earnings immediately. Sales related to trading activities are recorded net, and margins earned on such transactions are included as a component of net sales. Net sales and cost of goods sold, if reported on a gross basis for these activities, would be increased by $12,095.9 million and $13,933.1 million for the nine months ended September 30, 2013 and 2012, respectively.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(3) Summary of Significant Accounting Policies (Continued)

(k)   Income Taxes

        As a limited liability company, the Company does not pay U.S. federal or state income taxes under the provisions of the Internal Revenue Code. However, the Company's Canadian operations are subject to tax in its local jurisdiction.

        The Company recognizes the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.

(l)    Debt Issuance Costs

        The Company incurred certain financing costs associated with debt issuance (note 9). These costs were capitalized and are being amortized to expense using the effective interest rate method.

(4) Goodwill and Intangible Assets

        Goodwill represents the excess of the purchase price over the estimated fair value of the net tangible and intangible assets acquired. The Company's goodwill includes goodwill that was allocated by The Gavilon Group as part of the overall purchase price allocation for all legal entities acquired. Factors that contributed to a purchase price resulting in goodwill included the Company's favorable market position in profitable and growing markets, favorable logistics and asset network, and intellectual capital associated with the Company. Goodwill is fully tax deductible to the members.

        The fair value of identifiable intangible assets consist of customer relationships (7 year weighted average useful life) and contractual obligations. Identifiable intangible assets as of September 30, 2013 and December 31, 2012 are as follows (in millions):

 
  Gross
carrying
amounts
  Accumulated
amortization
  Net  

September 30, 2013:

                   

Customer relationships

  $ 43.1     (32.1 )   11.0  

Contractual obligations

    7.5     (7.5 )    
               

Total

  $ 50.6     (39.6 )   11.0  
               
               

 

 
  Gross
carrying
amounts
  Accumulated
amortization
  Net  

December 31, 2012:

                   

Customer relationships

  $ 43.1     (27.3 )   15.8  

Contractual obligations

    7.5     (7.4 )   0.1  
               

Total

  $ 50.6     (34.7 )   15.9  
               
               

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(4) Goodwill and Intangible Assets (Continued)

        Aggregate amortization expense for amortizing intangible assets was $4.8 million and $4.9 million for the nine months ended September 30, 2013 and 2012, respectively. Estimated future amortization expense is $1.6 million for the last three months of 2013, $6.2 million for 2014, $3.1 million for 2015, $0.1 million for 2016.

(5) Derivatives and Hedging Activities

        The Company purchases and sells commodities, such as gas, ethanol, natural gas, biodiesel and crude oil. The Company generally follows a policy of using commodity derivatives to minimize its net position of commodity inventories and forward cash purchase and sales contracts. The Company also uses commodity derivatives as components of market strategies designed to enhance margins. The results of these strategies can be significantly impacted by factors such as the volatility of the relationship between the value of commodity derivatives and the cash prices of the underlying commodities, counterparty contract defaults, and volatility of transportation markets.

        Changes in the fair value of commodity derivatives are recognized in earnings immediately, except for certain energy contracts and interest rate swaps that have been designated in a cash flow hedging relationship. The Company reports the fair value of its derivative assets and liabilities, including derivatives used in hedging relationships, on the combined balance sheets, as commodity and other contracts at fair value.

        For risk management purposes, the Company utilizes fair value hedges, cash flow hedges, and economic hedges. In addition to the use of derivative instruments to manage commodity price risk, the Company also enters into certain commodity derivative instruments for trading purposes. The majority of the Company's purchase and sales contracts qualify as derivative instruments and the change in fair value is reported in net sales and cost of sales in the accompanying combined statements of operations.

        For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or initially reported as a component of accumulated other comprehensive income and then recorded in income in the period or periods during which the hedged forecasted transaction affects income.

        The Company's policy is to report gains and losses associated with derivatives as follows:

Contract/derivative nature
  Line item
Commodities   Net sales
Interest rate swap   Interest expense

        While a majority of the Company's use of derivative instruments is to manage market risks by economically hedging the Company's inventory and forward purchase and sales commitments, the Company also designates cash flow hedges. The Company has designated cash flow hedges associated with the future purchase and sales of natural gas. The object of the Company's cash flow hedges is to fix the price of natural gas purchase and sales at existing market prices that the Company deems favorable.

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Table of Contents


GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(5) Derivatives and Hedging Activities (Continued)

        The Company entered into an interest rate swap agreement to manage the variability of cash flows over certain portions of the interest payments related to the variable rate on the term loan (note 9). The interest rate swap agreement used by the Company has been recorded at fair value in the combined balance sheets with changes in fair value recorded in accumulated other comprehensive income. This amount is subsequently reclassified into interest expense as a yield adjustment of the hedged interest payments in the same period in which the related interest affects earnings. Amounts subsequently reclassified into interest expense during the year were immaterial, and no ineffectiveness was recognized. During the nine months ended September 30, 2013, the Company settled the interest rate swap agreement for a payment of $1.1 million.

        As of December 31, 2012, the fair value of the Company's interest rate swap agreement designated in a cash flow hedging relationship was an unrealized loss of $1.8 million. As of September 30, 2013 and December 31, 2012, the fair value of the Company's natural gas futures designated in a cash flow hedging relationship was $0.7 million and $3.3 million, respectively.

        The following table provides information about the gain or loss recognized in income and other comprehensive income (loss) on the Company's cash flow hedging derivative instruments for the nine months ended September 30, 2013 and 2012 (in thousands). Also, the information presents the notional volume of outstanding cash flow hedge derivative contracts by type of instrument.

Cash Flow Hedges

 
  Gain (loss)
recognized in
AOCI on
derivatives
(effective portion)
   
   
   
   
 
 
  Gain (loss)
reclassified from AOCI
into income (effective portion)
  Gain (loss) recognized in
income on derivatives
(ineffective portion)
 
 
   
  2013 Amount    
  2013 Amount  
Commodity type
  2013 Amount   Location   Location  

Natural gas

  $ 2,162   Net sales   $ 4,157   Net sales   $  

Interest rate swaps

    1,794   Interest expense       Interest expense      

 

Commodity type
  2012 Amount   Location   2012 Amount   Location   2012 Amount  

Natural gas

  $ 554   Net sales   $ 18,646   Net sales   $  

Interest rate swaps

    (213 ) Interest expense       Interest expense      

 

Derivative instrument
  Notional
contract
volumes (as of
September 30,
2013)
  Notional
contract
volumes (as of
December 31,
2012)
 

Natural gas futures (MMBtu's)

    3,088     931  

Interest rate swaps (millions of $)

        36  

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(5) Derivatives and Hedging Activities (Continued)

        The following table summarizes the Company's outstanding interest rate swap agreement as of December 31, 2012:

Term
  Notional
amount
  Fixed
rate
  Variable
rate
 

1/24/11 - 3/31/18

  36 million     2.393     0.311  

        The Company did not exclude any components of the derivatives instruments' gains or losses from the assessment of hedge effectiveness for its cash flow hedging relationships.

        The Company has designated fair value hedges used to hedge certain crude oil inventories. The following table provides information about the gain or loss recognized in income on the Company's fair value hedging derivative instruments for the nine months ended September 30, 2013 and 2012 (in thousands). Also, the information presents the notional volume (in thousands) of outstanding derivative contracts designated in the fair value hedging relationships at September 30, 2013 and December 31, 2012.

Fair Value Hedges

 
  Gain (loss) recognized in
income on derivatives
  Gain (loss) recognized in
income on hedged item
  Gain (loss) recognized in
income on derivatives
(ineffective portion)
 
Commodity type
  Location   2013 Amount   Location   2013 Amount   Location   2013 Amount  

Crude oil inventory

  Net sales   $ (27,879 ) Net sales   $ 6,962   Net sales   $ (20,917 )

 

Commodity type
  Location   2012 Amount   Location   2012 Amount   Location   2012 Amount  

Crude oil inventory

  Net sales   $ 16,636   Net sales   $ (11,972 ) Net sales   $ 4,664  

 

Derivative instrument
  Notional
contract
volumes (as of
September 30,
2013)
  Notional
contract
volumes (as of
December 31,
2012)
 

Crude oil futures (barrels)

    580     9,661  

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(5) Derivatives and Hedging Activities (Continued)

        The following table summarizes the Company's notional volumes for their economic and trading derivative financial instruments as of September 30, 2013 and December 31, 2012 (amounts in thousands) by type of instrument:

 
  Exchange-
traded
  Non-exchange
traded
 
September 30, 2013
  (Short) long   (Short)   Long  

Natural gas (MMBtu's):

                   

Futures

    1,670          

Options

    379          

Swaps

    (350 )   (40,026 )   73,353  

Forwards

    (8,538 )            

Oil (barrels):

                   

Futures

    (684 )        

Forwards

        (87,224 )   87,021  

 

 
  Exchange-
traded
   
   
 
 
  Non-exchange
traded
 
 
  Net
(short) long
 
December 31, 2012
  (Short)   Long  

Natural gas (MMBtu's):

                   

Futures

    (4,700 )        

Options

             

Swaps

    (7,238 )       78  

Forwards

        (6,551 )    

Oil (barrels):

                   

Futures

    (3,262 )        

Options

    35          

Forwards

        (2,112 )   2,396  

        The Company has established guidelines, controls, and limits to manage and mitigate credit risk within risk tolerances established by the Company's Risk Committee. In addition, the Company has a credit committee that includes senior executives who meet on a regular basis to review the Company's credit activities and monitor compliance with the policies adopted by the Company. The Company attempts to mitigate its credit exposure by setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through prepayments, letters of credit, and other security agreements, such as inventory, property, or other tangible assets. The use of master netting agreements is driven by industry practice, and anticipated volumes and complexity of the business relationship with the counterparty. The Company assumes credit and performance risk associated with commodity derivative contracts within the energy and agriculture industries; however, no counterparty was greater than 10% of the Company's net exposure.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(5) Derivatives and Hedging Activities (Continued)

        The Company has policies that limit the dollar risk exposure for each of its businesses. The Company also monitors the amount of associated counterparty credit risk for all nonexchange-traded transactions. The Company's trading activities are limited in terms of maximum dollar exposure, as measured by a value-at-risk methodology, and monitored to ensure compliance.

        As of September 30, 2013, the Company held certain derivative contracts with settlement dates through 2016. However, approximately 95% of the Company's notional amount of commodity derivative contracts have settlement dates of less than one year.

(6) Equity Method Investments

        The Company's equity method investment in Glass Mountain Pipeline of $100.1 million at September 30, 2013 and $73.6 million at December 31, 2012 relates to a 50% interest in a development-stage limited liability company formed in May 2012. Glass Mountain pipeline's operations consist of construction of an intrastate crude oil common carrier pipeline system in Oklahoma. Glass Mountain's total assets as of September 30, 2013 are $159.5 million and primarily represent cash and construction in progress. Glass Mountain's total liabilities as of September 30, 2013 are $21.3 million and primarily represent construction-related payables.

(7) Inventories

        The major classes of inventories at September 30, 2013 and December 31, 2012 are as follows (in millions):

 
  September 30,
2013
  December 31,
2012
 

Crude oil inventories carried at fair value

  $ 56.3     873.3  

Inventories carried at lower of cost or market:

             

Crude oil

    14.6     6.8  

Natural gas

    28.9     31.2  

Fuels

    76.7     57.6  

Other

        0.5  
           

  $ 176.5     969.4  
           
           

(8) Fair Value Measurements

        Financial assets and liabilities carried at fair value will be classified and disclosed in one of the following three categories:

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(8) Fair Value Measurements (Continued)

        Exchange-traded futures and options contracts are valued based on unadjusted quoted prices in active markets and are classified within Level 1. The Company's forward commodity purchase and sale contracts are classified as a Level 2 measurement. The Company estimates fair values based on exchange quoted prices, adjusted as appropriate for differences in local markets. These differences are generally valued using inputs from broker or dealer quotations, or market transactions in either the listed or over-the-counter (OTC) markets. The determination of the fair values also factor the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit, and priority interests), and also the impact of the Company's nonperformance risk on its liabilities.

        The Company also utilizes a midmarket pricing convention (the midpoint price between bid and ask prices) for valuing a significant portion of its assets and liabilities measured and reported at fair value. The Company is able to classify fair value balances based on the observability of inputs.

        The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 and December 31, 2012. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels.

 
  September 30, 2013  
 
  Level 1   Level 2   Level 3   Nettings   Total  

Assets (in millions):

                               

Inventory

  $ 56.3                 56.3  

Derivative assets

    14.1     1,218.0         (1,186.2 )   45.9  

Liabilities (in millions):

                               

Derivative liabilities

  $     1,198.4         (1,186.2 )   12.2  

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(8) Fair Value Measurements (Continued)


 
  December 31, 2012  
 
  Level 1   Level 2   Level 3   Nettings   Total  

Assets (in millions):

                               

Inventory

  $ 873.3                 873.3  

Derivative assets

    13.1     2,930.1         (2,884.8 )   58.4  

Liabilities (in millions):

                               

Derivative liabilities

  $     2,917.0         (2,884.8 )   32.2  

(9) Credit Facility Agreement

        The Company has a $650 million Credit Facility Agreement (the credit agreement) expiring in June 2014. While the credit agreement provides for up to $650 million in credit, the actual credit available is based on eligible assets of the Company as determined by the provisions included in the credit agreement and is collateralized by inventory. At September 30, 2013, the Company had no cash borrowings under the credit agreement and had outstanding letters of credit of $325.7 million.

        The Company may elect to borrow under the credit agreement based on either prime rate plus 1.5% or London Interbank Offered Rate (LIBOR) plus 2.5%. Debt issue costs of $1.4 million were capitalized related to the credit facility agreement in 2013.

        The Company is required to comply with certain financial covenants related to minimum interest coverage ratio and maximum leverage ratio. In addition, the credit agreement limits the amount of additional borrowings by the Company.

        The Company retired the Credit Facility Agreement upon the sale of the Company in December 2013, as described in note 15.

(10) Accumulated Other Comprehensive Income

        The following table summarizes the balances of accumulated other comprehensive income (in millions):

 
  September 30,
2013
  December 31,
2012
 

Cash flow hedging derivatives

  $ 1.3     1.5  

Available-for-sale securities

    (0.1 )    

Currency translation adjustment

    0.1     0.1  
           

  $ 1.3     1.6  
           
           

(11) Contingencies

        The Company is party to a number of claims arising out of the operation of its business. Management records charges for probable losses that can be estimated. After taking into account liabilities recorded for all of the foregoing matters, management believes the ultimate resolution of

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(11) Contingencies (Continued)

such matters should not have a material adverse effect on the Company's combined financial position, results of operations, or liquidity. Costs of legal services are recognized in earnings as services are provided.

(12) Discontinued Operations

        During 2012, the Company completed restructuring initiatives that eliminated the operations of the Import/Export Ethanol, Glycerin, and weather and portfolio trading business units. Additionally, during 2012, the Company's management approved a plan to sell the Thackerville Propane Terminal. These operations are classified as held for sale and included in discontinued operations.

        These business lines meet the criteria for being reported as discontinued operations and have been segregated from continuing operations. The following table summarizes the results from discontinued operations (in millions):

 
  Net sales   Net loss  

Nine months ended September 30, 2013:

             

Import/export ethanol

  $ (0.3 )   (0.7 )

Glycerin

    0.5     (0.8 )

Thackerville propane terminal

        (0.1 )

Weather and portfolio trading

        (0.2 )
           

Total

  $ 0.2     (1.8 )
           
           

Nine months ended September 30, 2012:

             

Import/export ethanol

  $ (13.0 )   (18.4 )

Glycerin

    9.5     (4.1 )

Thackerville propane terminal

        (0.1 )

Weather and portfolio trading

    (1.0 )   (1.5 )
           

Total

  $ (4.5 )   (24.1 )
           
           

(13) Related-Party Transactions

        The Gavilon Group provides a variety of services to the Company, such as information technology, treasury and cash management, payroll and human resources, legal, tax, facilities, general accounting and other corporate functions. Where possible, The Gavilon Group directly allocates costs to the Company based on usage or other direct allocation methods. Direct allocations to the Company are generally related to information technology, risk management, human resources, business development, compliance and facilities. The direct allocations are included in corporate allocations in the accompanying combined statements of operations, and were $3.1 million and $5.9 million for the nine months ended September 30, 2013 and 2012, respectively.

        In addition to direct allocations from The Gavilon Group, indirect corporate expenses are allocated to the Company. These expenses are allocated to the Company based on historical company

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(13) Related-Party Transactions (Continued)

policy and may not be reflective of actual expenses incurred by the Company on a stand-alone basis. Indirect allocations charged to the Company are related to corporate departments such as executive, corporate finance and treasury, legal, communications, and stock-based compensation and were $4.0 million and $17.0 million for the nine months ended September 30, 2013 and 2012, respectively, and included in corporate allocated expense in the accompanying combined statements of operations.

        The Gavilon Group also allocates corporate interest expense to the Company based on total invested and trade working capital utilized by the business and may not be reflective of interest expense incurred on a standalone basis. Interest expense allocated by The Gavilon Group to the Company was $17.9 million and $29.4 million for the nine months ended September 30, 2013 and 2012, respectively, and is included in the accompanying combined statements of operations.

        The amounts due to (from) The Gavilon Group are classified as payable due to (from) parent in current liabilities within the accompanying combined balance sheet as of December 31, 2012 and reflect the net cash transferred between the Companies for operating capital requirements, which includes corporate expense and interest allocations.

(14) Blender's Tax Credit

        The Company received $29.3 million in January 2013 for a blender's tax credit from the federal government for blending biodiesel sold during 2012. This has been recognized in net sales during fiscal 2013 consistent with the enactment of the tax rule change.

(15) Subsequent Event

        On December 2, 2013, The Gavilon Group completed the sale of Gavilon, LLC to NGL Energy Partners LP for $890.0 million of cash. The purchase price is subject to adjustment for certain specified working capital items. The agreement for the sale of Gavilon, LLC specified that Gavilon, LLC would have $198 million of working capital, as defined in the agreement, at the closing date. At the time of closing, Gavilon, LLC paid a distribution to its parent of approximately $187 million, which was calculated as the amount by which working capital, as defined in the agreement, was estimated to exceed $198 million. Since NGL Energy Partners LP is a pass-through entity for income tax purposes, no pro forma income tax expense or benefit has been reported in these notes to unaudited condensed combined financial statements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To NGL Energy Partners LP

        We have audited the accompanying combined balance sheets of the Businesses Associated with TransMontaigne Inc. acquired by NGL Energy Partners LP (the "Businesses) as of December 31, 2013 and 2012, and the related combined statements of comprehensive income (loss), equity, and cash flows for the years then ended. These financial statements are the responsibility of the Businesses' management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Businesses are not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Businesses' internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, such combined financial statements present fairly, in all material respects, the financial position of the Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP as of December 31, 2013 and 2012, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
November 5, 2014
(December 24, 2014 as to Note 12)

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Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP

Combined Balance Sheets

(In thousands)

 
  December 31,
2013
  December 31,
2012
 

ASSETS

             

Current assets:

             

Cash and cash equivalents

  $ 74,762   $ 15,156  

Rack sales accounts receivable, net

    243,520     307,757  

Pipeline sales accounts receivable

    684,881     520,944  

Inventories in pipelines and terminals

    629,567     660,044  

Inventories in transit via truck and rail

    53,216     59,703  

Derivative contracts

    47,372     13,390  

Other pipeline accrued receivables

    6,123     2,808  

Other

    17,548     15,067  
           

    1,756,989     1,594,869  

Property, plant and equipment, net

    445,495     467,187  

Investment in unconsolidated affiliates

    211,605     105,164  

Other assets

    18,357     19,469  
           

  $ 2,432,446   $ 2,186,689  
           
           

LIABILITIES AND EQUITY

             

Current liabilities:

             

Accounts payable

  $ 64,351   $ 100,651  

Product purchases accounts payable

    785,112     705,863  

Excise taxes payable

    39,648     55,139  

Inventories due under exchange agreements

    31,280     35,343  

Derivative contracts

    30,066     11,947  

Accrued environmental obligations

    4,303     6,215  

Variation margin payables

    35,528     30,633  

Other pipeline accrued payables

    20,589     18,953  

Other accrued liabilities

    23,263     27,935  
           

    1,034,140     992,679  

Bank debt

    212,000     184,000  

Other

    9,362     11,895  
           

Total liabilities

    1,255,502     1,188,574  
           

Equity:

             

Equity attributable to noncontrolling interests

    359,418     299,205  

Equity attributable to parent

    817,526     698,910  
           

    1,176,944     998,115  
           

  $ 2,432,446   $ 2,186,689  
           
           

   

See accompanying notes to combined financial statements.

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Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP

Combined Statements of Comprehensive Income (Loss)

(In thousands)

 
  Year ended
December 31, 2013
  Year ended
December 31, 2012
 

Marketing and distribution:

             

Revenues

  $ 8,579,362   $ 10,877,459  

Cost of product sold and other direct costs and expenses

    (8,463,720 )   (10,983,348 )
           

Net operating margins (loss), exclusive of depreciation and amortization shown separately below

    115,642     (105,889 )
           

Terminals and pipelines:

             

Revenues

    59,844     52,715  

Direct costs and expenses

    29,414     (21,234 )
           

Net operating margins, exclusive of depreciation and amortization shown separately below

    30,430     31,481  
           

Total net operating margins (loss)

    146,072     (74,408 )
           

Costs and expenses:

             

Selling, general and administrative

    (65,019 )   (67,971 )

Depreciation and amortization

    (34,261 )   (32,267 )

Gain (loss) on disposition of assets, net

    (2,022 )   856  

Earnings (loss) from unconsolidated affiliates

    (321 )   558  
           

Total costs and expenses

    (101,623 )   (98,824 )
           

Operating income (loss)

    44,449     (173,232 )
           

Other income (expenses):

             

Interest expense

    (5,974 )   (6,549 )

Foreign currency transaction gain (loss)

    (13 )   51  
           

Total other expenses

    (5,987 )   (6,498 )
           

Earnings (loss) before income taxes

    38,462     (179,730 )

Income tax expense

    (242 )   (188 )
           

Net income (loss)

    38,220     (179,918 )

Noncontrolling interests share in earnings of TransMontaigne Partners

    (23,590 )   (27,086 )
           

Net income (loss) attributable to parent

    14,630     (207,004 )

Other comprehensive income—foreign currency translation adjustments attributable to noncontrolling interests

    56     128  

Other comprehensive income—foreign currency translation adjustments attributable to parent

    27     63  
           

Comprehensive income (loss)

  $ 14,713   $ (206,813 )
           
           

   

See accompanying notes to combined financial statements.

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Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP

Combined Statements of Equity

Years ended December 31, 2012 and 2013

(in thousands)

 
  Equity
attributable to
noncontrolling
interests
  Equity
attributable to
Parent, Net
  Total
equity
 

Balance at December 31, 2011

  $ 301,478   $ 1,280,928   $ 1,582,406  

Distributions paid to noncontrolling TransMontaigne Partners' common units

    (29,801 )       (29,801 )

Purchase of common units by TransMontaigne Partners' long-term incentive plan

    (239 )       (239 )

Deferred equity-based compensation related to restricted phantom units and other

    553         553  

Net income (loss)

    27,086     (207,004 )   (179,918 )

Net capital distributed to parent company

        (375,077 )   (375,077 )

Other comprehensive income—foreign currency translation adjustments

    128     63     191  
               

Balance at December 31, 2012

    299,205     698,910     998,115  

Proceeds from offering of TransMontaigne Partners' common units

    68,774         68,774  

Distributions paid to noncontrolling TransMontaigne Partners' common units

    (32,419 )       (32,419 )

Purchase of common units by TransMontaigne Partners' long-term incentive plan

    (335 )       (335 )

Deferred equity-based compensation related to restricted phantom units and other

    289         289  

Net income

    23,590     14,630     38,220  

Net capital contributed by parent company

        103,825     103,825  

Other comprehensive income—foreign currency translation adjustments

    56     27     83  

Foreign currency translation adjustments reclassified in entirety into loss on disposition of assets, net, upon the sale of TransMontaigne Partners' Mexico operations

    258     134     392  
               

Balance at December 31, 2013

  $ 359,418   $ 817,526   $ 1,176,944  
               
               

   

See accompanying notes to combined financial statements.

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Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP

Combined Statements of Cash Flows

(In thousands)

 
  Year ended
December 31,
2013
  Year ended
December 31,
2012
 

Cash flows from operating activities:

             

Net income (loss)

  $ 38,220   $ (179,918 )

Adjustments to reconcile net income to net cash provided (used) by operating activities:

             

Depreciation and amortization

    34,261     32,267  

Loss (gain) on disposition of assets, net

    2,022     (856 )

Amortization of financing costs

    1,373     1,165  

Loss (earnings) from unconsolidated affiliates

    321     (558 )

Distributions from unconsolidated affiliates

    1,467     1,435  

Amortization of deferred revenue, utility deposits returned and other

    (6,060 )   (3,430 )

Changes in operating assets and liabilities:

             

Rack sales accounts receivable, net

    64,111     61,962  

Pipeline sales accounts receivable

    (163,937 )   (96,685 )

Inventories in pipelines and terminals

    30,477     180,905  

Inventories in transit via truck and rail

    6,487     10,457  

Derivative contracts

    (15,864 )   688  

Other pipeline accrued receivables

    (3,315 )   166  

Other current assets

    (3,109 )   (955 )

Accounts payable

    (33,531 )   30,194  

Product purchases accounts payable

    79,249     308,006  

Excise taxes payable

    (15,489 )   (6,855 )

Inventory due under exchange agreements

    (4,063 )   15,435  

Accrued environmental liabilities

    (1,912 )   238  

Variation margin payables

    4,895     11,688  

Other pipeline accrued payables

    1,636     2,291  

Other current liabilities

    (2,187 )   (1,652 )
           

Net cash provided by operating activities

    15,052     365,988  
           

Cash flows from investing activities:

             

Investments in unconsolidated affiliates

    (108,229 )   (80,166 )

Capital expenditures

    (17,405 )   (31,178 )

Proceeds from sale of assets

    2,294     19,085  
           

Net cash used in investing activities

    (123,340 )   (92,258 )
           

Cash flows from financing activities:

             

Proceeds from issuance of TransMontaigne Partners' common units

    68,774      

Borrowings of bank debt

    168,500     147,000  

Repayments of bank debt

    (140,500 )   (83,000 )

Deferred debt issuance costs

        (736 )

Net capital contributed by (distributed to) parent company

    103,825     (375,077 )

Distributions paid to noncontrolling TransMontaigne Partners' common units                 

    (32,419 )   (29,801 )

Purchase of common units by TransMontaigne Partners' long-term incentive plan

    (335 )   (239 )
           

Net cash provided by (used in) financing activities

    167,845     (341,853 )
           

Increase (decrease) in cash and cash equivalents

    59,557     (68,123 )

Foreign currency translation effect on cash

    49     63  
           

Cash and cash equivalents at beginning of year

    15,156     83,216  
           

Cash and cash equivalents at end of year

  $ 74,762   $ 15,156  
           
           

Supplemental disclosures of cash flow information:

             

Cash paid for interest expense

  $ (4,443 ) $ (5,430 )
           
           

Property, plant and equipment acquired with accounts payable

  $ 718   $ 3,473  
           
           

   

See accompanying notes to combined financial statements.

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Notes to Combined Financial Statements

Years ended December 31, 2013 and 2012

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a)   Nature of business

        The accompanying combined financial statements include the accounts of all operations of the Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP (collectively, the "Company", "we", "us" or "our"). On July 1, 2014, Morgan Stanley consummated the sale of its indirect 100% ownership interest in the Business to NGL Energy Partners LP ("NGL"). TransMontaigne Inc. is the indirect parent and sole member of TransMontaigne GP L.L.C., which is the sole general partner ("General Partner") of TransMontaigne Partners L.P. ("TLP" or the "Partnership"), a publicly traded master limited partnership. The sale also included Morgan Stanley's limited partnership interests in TLP, the assignment from an affiliate of Morgan Stanley to NGL of certain terminaling services agreements with TLP, and the transfer of certain inventory owned by Morgan Stanley (collectively, the "Transaction"). The Transaction does not involve the sale or purchase of any of the limited partnership units in TLP held by the public and the TLP limited partnership units continue to trade on the New York Stock Exchange.

        TransMontaigne Inc., ("TransMontaigne") is a Delaware corporation headquartered in Denver, Colorado, that was formed in 1995 as a refined petroleum products marketing and distribution company. TransMontaigne and its wholly-owned subsidiaries conduct operations in the United States primarily in the Southeast, Florida, and Midwest regions. TransMontaigne primarily provides integrated marketing and distribution services to end-users of refined petroleum products and, to a lesser extent, users of crude oil and renewable fuels.

        TransMontaigne's less than wholly-owned subsidiary includes the publicly traded master limited partnership of TLP. TLP was formed in February 2005 as a Delaware limited partnership to own and operate refined petroleum products terminaling and transportation facilities. TLP conducts its operations in the United States along the Gulf Coast, in the Midwest, in Houston and Brownsville, Texas, along the Mississippi and Ohio rivers, and in the Southeast. TLP provides integrated terminaling, storage, transportation and related services for companies engaged in the trading, distribution and marketing of light refined petroleum products, heavy refined petroleum products, crude oil, chemicals, fertilizers and other liquid products. TransMontaigne and NGL, subsequent to the Transaction, have an interest in TLP through the ownership of approximately 20% of the limited partner interests, a 2% general partner interest and the incentive distribution rights.

(b)   Basis of presentation and use of estimates

        In preparing the combined financial statements, we have followed the accounting policies of Morgan Stanley, a broker—dealer, and TransMontaigne Inc., which are in accordance with United States generally accepted accounting principles or "GAAP". The combined financial statements of the Company have been prepared from the separate records maintained by Morgan Stanley and TransMontaigne Inc. and may not necessarily be indicative of the conditions that would have existed, or the results of operations, if the Company had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various assets comprising the Company, Morgan Stanley's net investment in the business is shown as net parent equity, in lieu of owner's equity, in the combined financial statements. All intercompany balances have been eliminated. Transactions between us and Morgan Stanley operations have been identified in the combined financial statements as transactions between affiliates. In the opinion of management, all adjustments have been reflected that are necessary for a fair presentation of the combined financial statements.

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The following estimates, in our opinion, are subjective in nature and require the exercise of judgment: allowance for doubtful accounts; fair value of inventories; fair value of derivative contracts; useful lives of our plant and equipment; and accrued environmental obligations. Changes in these estimates and assumptions will occur as a result of the passage of time and the occurrence of future events. Actual results could differ from these estimates.

(c)   Accounting for marketing and distribution operations

        In our marketing and distribution operations, we enter into contracts to purchase refined petroleum products, renewable fuel products and crude oil, schedule them for delivery to our terminals, as well as terminals owned by third parties, and then sell those products to our customers through rack spot sales, contract sales, and bulk sales. Revenue from our sales of physical inventory is recognized pursuant to the accrual method of accounting. Revenue from rack spot sales and contract sales is recognized when the product is delivered to the customer through a truck loading rack or marine fueling equipment. Revenue from bulk sales is recognized when the title to the product is transferred to the customer, which generally occurs upon delivery of the sale. Taxes collected from customers and remitted to taxing authorities are reported on a net basis in the combined statements of comprehensive income (loss).

        Storage and transportation costs attributable to our marketing and distribution operations are included in cost of product sold in the accompanying combined statements of comprehensive income (loss). Storage costs at our terminals include the direct operating costs and expenses associated with our terminal operations, out of which we market and distribute our petroleum products. Such costs consist of directly related wages and employee benefits for employees working at the terminals, utilities, communications, repairs and maintenance, rent, property taxes, vehicle expenses, environmental compliance costs, materials and supplies. Storage costs at terminals owned by third parties include contractual amounts agreed to between us and third parties under terminaling services agreements.

        Gains and losses associated with hedging the value of petroleum products owned and included in inventory and trading around that inventory are recorded on a net basis within cost of product sold in the accompanying combined statements of comprehensive income (loss).

(d)   Accounting for terminal and pipeline operations

        In connection with our terminal and pipeline operations, we utilize the accrual method of accounting for revenue and expenses. We generate revenue in our terminal and pipeline operations from transactions with unaffiliated third parties primarily for terminaling services fees and pipeline transportation fees. Terminaling services revenue is recognized ratably over the term of the agreement for storage fees and minimum revenue commitments that are fixed at the inception of the agreement and when product is delivered to the customer for fees based on a rate per barrel of throughput; pipeline transportation revenue is recognized when the product has been delivered to the customer at the specified delivery location.

        Direct operating costs and expenses for our terminal and pipeline operations consist of direct operating costs and expenses associated with our terminal operations under contract with unaffiliated

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

third parties. Such costs consist of directly related wages and employee benefits for employees working at the terminals, utilities, communications, repairs and maintenance, rent, property taxes, vehicle expenses, environmental compliance costs, materials and supplies.

(e)   Cash and cash equivalents

        We consider all short-term investments with a remaining maturity of three months or less at the date of purchase to be cash equivalents.

        Restricted cash represents cash deposits to help sustain the TransMontaigne credit facility committed amounts. Restricted cash amounts of approximately $1.0 million and $1.1 million at December 31, 2013 and 2012, respectively, are included in other current assets in the accompanying combined balance sheets.

(f)    Inventories

        Our inventories are composed of volumes held in pipelines and terminals and volumes in transit via truck and rail. Our inventories consist of refined petroleum products, primarily gasolines and distillates, ethanol and crude oil. As these inventories are directly held by Morgan Stanley, which is a broker/dealer, the inventories presented in the accompanying combined balance sheets are carried at fair value to follow the practices of broker/dealer accounting and to be consistent with Morgan Stanley's historical accounting policies. As noted in the Basis of Presentation, we have applied the parent entity's accounting policies. Historical cost was not reasonably available from Morgan Stanley.

(g)   Derivative contracts and variation margin payables

        Certain of our commodity contract purchases and sales with firmly committed pricing structures qualify as over-the-counter derivative instruments. Our over-the-counter derivative instruments are reported as assets and liabilities and are measured at fair value in the accompanying combined balance sheets in accordance with generally accepted accounting principles. The net changes in the fair value of our over-the-counter derivative contracts are included within cost of product sold in the accompanying combined statements of comprehensive income (loss).

        We also enter into derivative risk management contracts, principally NYMEX futures contracts, which are measured at fair value to manage our exposure to changes in commodity prices that are intended to offset the changes in the values of our inventories. We evaluate our market risk exposure from an overall portfolio basis that considers changes in physical inventories. At December 31, 2013 and 2012, net unrealized losses on our unsettled futures derivative contracts were recorded as variation margin payables in the accompanying combined balance sheets and are included within cost of product sold in the accompanying combined statements of comprehensive income (loss).

(h)   Inventories due under exchange agreements

        We enter into refined product exchange agreements with major oil companies. Exchange agreements generally are fixed term agreements that involve our receipt of a specified volume of product at one location in exchange for delivery by us of a specified volume of product at a different location. The amount recorded represents the fair value of inventory due to others under exchange agreements. At December 31, 2013 and 2012, current liabilities include inventory due to others under

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

exchange agreements of 271,429 barrels and 277,652 barrels, respectively, with a fair value of approximately $28.4 million and $28.3 million, respectively.

(i)    Property, plant and equipment

        Depreciation is computed using the straight-line method. Estimated useful lives are 15 to 25 years for terminals and pipelines and 3 to 25 years for furniture, fixtures and equipment. All items of property, plant and equipment are carried at cost. Expenditures that increase capacity or extend useful lives are capitalized. Repairs and maintenance are expensed as incurred.

        We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset group may not be recoverable based on expected undiscounted future cash flows attributable to that asset group. If an asset group is impaired, the impairment loss to be recognized is the excess of the carrying amount of the asset group over its estimated fair value.

(j)    Investments in unconsolidated affiliates

        We account for investments in unconsolidated affiliates, which we do not control but do have the ability to exercise significant influence over, using the equity method of accounting. Under this method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions received, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the book value of the net assets of the investment entity. We evaluate our investments in unconsolidated affiliates for impairment whenever events or circumstances indicate there is a loss in value of the investment that is other than temporary. In the event of impairment, we would record a charge to earnings to adjust the carrying amount to fair value.

(k)   Environmental obligations

        We accrue for environmental costs that relate to existing conditions caused by past operations when estimable. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs. Liabilities for environmental costs at a specific site are initially recorded, on an undiscounted basis, when it is probable that we will be liable for such costs, and a reasonable estimate of the associated costs can be made based on available information. Such an estimate includes our share of the liability for each specific site and the sharing of the amounts related to each site that will not be paid by other potentially responsible parties, based on enacted laws and adopted/regulations and policies. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation, technology changes, alternatives available and the evolving nature of environmental laws and regulations.

        We periodically file claims for insurance recoveries of certain environmental remediation costs with our insurance carriers under our comprehensive liability policies.We recognize our insurance recoveries in the period that we assess the likelihood of recovery as being probable (i.e., likely to occur).

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

(l)    Asset retirement obligations

        Asset retirement obligations are legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal use of the asset. Generally accepted accounting principles require that the fair value of a liability related to the retirement of long-lived assets be recorded at the time a legal obligation is incurred. Once an asset retirement obligation is identified and a liability is recorded, a corresponding asset is recorded, which is depreciated over the remaining useful life of the asset. After the initial measurement, the liability is adjusted to reflect changes in the asset retirement obligation. If and when it is determined that a legal obligation has been incurred, the fair value of any liability is determined based on estimates and assumptions related to retirement costs, future inflation rates and interest rates. Our long-lived assets consist of above-ground storage facilities and underground pipelines. We are unable to predict if and when these long-lived assets will become obsolete and require dismantlement. We have not recorded an asset retirement obligation, or corresponding asset, because the future dismantlement and removal dates of our long-lived assets are indeterminable and the amount of any associated costs are believed to be insignificant. Changes in our assumptions and estimates may occur as a result of the passage of time and the occurrence of future events.

(m)  Income taxes

        Our income taxes are presented on a separate return basis, although our historical operations were included in the U.S. federal and state filings of Morgan Stanley or its subsidiaries. We utilize the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date. We periodically assess the likelihood that we will be able to recover our deferred tax assets and reflect any changes in our estimate to the valuation allowance, with an adjustment to earnings.

        In assessing our need for a valuation allowance, we look to the future reversal of our taxable temporary differences, taxable income in carryback years, the feasibility of tax planning and estimated future taxable income. The valuation allowance may be affected by changes in tax law, statutory tax rates and estimated future income.

        TLP is treated as a partnership for federal income taxes. As a partnership, all income, gains, losses, expenses, deductions and tax credits generated by TLP flow through to the unitholders of the partnership.

(2) CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

        Our primary marketing and distribution areas are located in the Midwest, Florida and the Southeast regions of the United States. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other wholesalers. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. Our customers' historical and future credit positions are analyzed prior to extending credit. We manage our exposure to credit risk through credit analysis,

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(2) CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE (Continued)

credit approvals, credit limits and monitoring procedures, and for certain transactions we may request letters of credit, prepayments or guarantees.

        Pipeline sales accounts receivable consist of uncollected sales occurring while our inventory product is located in a pipeline, such as the Colonial and Plantation pipelines located in Southeast regions of the United States. Product sold in the pipeline never reaches our terminals. Whereas rack sales accounts receivable consist of uncollected sales sold out of our terminals, or third party terminals that we lease. Our pipeline sales tend to be to major integrated oil companies, for which our counterparty credit risk is deemed minimal, and thus we have not historically recorded any allowance for doubtful accounts related to these receivables. We maintain allowances for potentially uncollectible accounts receivable related to our rack sales. We write off accounts receivable against the allowance for doubtful accounts when collection efforts have been exhausted.

        Rack sales accounts receivable, net consists of the following (in thousands):

 
  December 31,
2013
  December 31,
2012
 

Trade accounts receivable

  $ 247,329   $ 313,194  

Less allowance for doubtful accounts

    (3,809 )   (5,437 )
           

  $ 243,520   $ 307,757  
           
           

        The following table presents a rollforward of our allowance for doubtful accounts (in thousands):

 
  Balance at
beginning
of period
  Charged to
expenses
  Deductions   Balance at
end of period
 

2013

  $ 5,437   $   $ (1,628 ) $ 3,809  

2012

  $ 5,438   $ 646   $ (647 ) $ 5,437  

        No single customer accounted for 10% or more of total revenues for the years ended December 31, 2013 or 2012.

        On the December 31, 2013 combined balance sheet, approximately $75 million of accounts receivable are reported net of accounts payable to the same counterparty.

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(3) INVENTORIES

        Our inventories are carried at fair value (see Note 1 of Notes to consolidated financial statements), and the classes of inventories are as follows (amounts and volume of barrels in thousands):

Inventories in pipelines and terminals:

 
  December 31,
2013
  December 31,
2012
 
 
  Amount   Barrels   Amount   Barrels  

Gasoline

  $ 400,120     3,618   $ 438,820     3,978  

Distillate

    220,702     1,736     155,828     1,200  

Ethanol

    7,946     98     38,667     401  

Crude oil

    799     8     19,480     211  

Other

            7,249     1,139  
                   

  $ 629,567     5,460   $ 660,044     6,929  
                   
                   

Inventories in transit via truck and rail:

 
  December 31,
2013
  December 31,
2012
 
 
  Amount   Barrels   Amount   Barrels  

Gasoline

  $ 16,725     176   $ 25,898     256  

Distillate

    13,516     111     3,501     30  

Ethanol

    17,193     218     27,141     288  

Crude oil

    5,782     59     1,019     11  

Other

            2,144     57  
                   

  $ 53,216     564   $ 59,703     642  
                   
                   

(4) PROPERTY, PLANT AND EQUIPMENT

        Property, plant and equipment, net is as follows (in thousands):

 
  December 31,
2013
  December 31,
2012
 

Land

  $ 57,568   $ 57,701  

Terminals, pipelines and equipment

    601,921     591,788  

Furniture, fixtures and equipment

    20,941     15,235  

Construction in progress

    3,691     8,101  
           

    684,121     672,825  

Less accumulated depreciation

    (238,626 )   (205,638 )
           

  $ 445,495   $ 467,187  
           
           

(5) INVESTMENT IN UNCONSOLIDATED AFFILIATES

        At December 31, 2013 and 2012, our investments in unconsolidated affiliates include a 42.5% ownership interest in Battleground Oil Specialty Terminal Company LLC ("BOSTCO") and a 50%

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(5) INVESTMENT IN UNCONSOLIDATED AFFILIATES (Continued)

interest in Frontera Brownsville LLC ("Frontera"). BOSTCO is a terminal facility construction project for approximately 7.1 million barrels of storage capacity at an estimated cost of approximately $535 million. BOSTCO is located on the Houston Ship Channel and began initial commercial operations in the fourth quarter of 2013. Frontera is a terminal facility located in Brownsville, Texas that includes approximately 1.5 million barrels of light petroleum product storage capacity, as well as related ancillary facilities.

        The following table summarizes our investments in unconsolidated affiliates:

 
  Percentage of
ownership
December 31,
  Carrying value
(in thousands)
December 31,
 
 
  2013   2012   2013   2012  

BOSTCO

    42.5 %   42.5 % $ 186,181   $ 78,930  

Frontera

    50 %   50 %   25,424     26,234  
                       

Total investments in unconsolidated affiliates

              $ 211,605   $ 105,164  
                       
                       

        At December 31, 2013 and 2012, our investment in BOSTCO includes approximately $6.4 million and $2.7 million, respectively, of excess investment related to a one time buy-in fee to acquire our 42.5% interest and capitalization of interest on our investment during the construction of BOSTCO. Excess investment is the amount by which our investment exceeds our proportionate share of the book value of the net assets of the BOSTCO entity.

        Earnings (loss) from investments in unconsolidated affiliates were as follows (in thousands):

 
  Year ended
December 31,
2013
  Year ended
December 31,
2012
 

BOSTCO

  $ (826 ) $  

Frontera

    505     558  
           

Total earnings from unconsolidated affiliates

  $ (321 ) $ 558  
           
           

        Additional capital investments in unconsolidated affiliates were as follows (in thousands):

 
  Year ended
December 31,
2013
  Year ended
December 31,
2012
 

BOSTCO

  $ 108,077   $ 78,930  

Frontera

    152     1,236  
           

Additional capital investments in unconsolidated affiliates

  $ 108,229   $ 80,166  
           
           

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(5) INVESTMENT IN UNCONSOLIDATED AFFILIATES (Continued)

        Cash distributions received from unconsolidated affiliates were as follows (in thousands):

 
  Year ended
December 31,
2013
  Year ended
December 31,
2012
 

BOSTCO

  $   $  

Frontera

    1,467     1,435  
           

Cash distributions from unconsolidated affiliates

  $ 1,467   $ 1,435  
           
           

        The summarized financial information of our unconsolidated affiliates was as follows (in thousands):

        Balance sheets:

 
  BOSTCO
December 31,
  Frontera
December 31,
 
 
  2013   2012   2013   2012  

Current assets

  $ 30,776   $ 21   $ 4,465   $ 4,209  

Long-term assets

    458,707     231,537     47,691     50,013  

Current liabilities

    (66,469 )   (52,233 )   (1,308 )   (1,754 )

Long-term liabilities

                 
                   

Net assets

  $ 423,014   $ 179,325   $ 50,848   $ 52,468  
                   
                   

        Statements of comprehensive income (loss):

 
  BOSTCO
Year ended
December 31,
  Frontera
Year ended
December 31,
 
 
  2013   2012   2013   2012  

Revenue

  $ 3,917   $   $ 12,388   $ 11,539  

Expenses

    (5,854 )   (7 )   (11,378 )   (10,423 )
                   

Net earnings and comprehensive income (loss)

  $ (1,937 ) $ (7 ) $ 1,010   $ 1,116  
                   
                   

(6) DERIVATIVE CONTRACTS

        The Company purchases and sells commodities, such as gasoline, distillate, ethanol and crude oil. The Company generally follows a policy of using over-the-counter commodity derivatives as components of market strategies designed to enhance margins. The results of these strategies can be significantly impacted by factors such as the volatility of the relationship between the value of commodity derivatives and the prices of the underlying commodities, counterparty contract defaults, and volatility of transportation markets.

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(6) DERIVATIVE CONTRACTS (Continued)

        The majority of the Company's commodity purchase and sales contracts qualify as over-the-counter derivative instruments and the change in fair value is reported in cost of product sold within the marketing and distribution section of the accompanying combined statements of comprehensive income (loss). Changes in the fair value of our derivatives are recognized in earnings. The Company reports the fair value of its over-the-counter derivative assets and liabilities on the combined balance sheets as derivative contract assets and liabilities.

        The Company has established guidelines to manage and mitigate credit risk within risk tolerances. The Company attempts to mitigate its credit exposure by setting tenor and credit limits commensurate with counterparty financial strength and obtaining master netting agreements. The use of master netting agreements is driven by industry practice, and anticipated volumes and complexity of the business relationship with the counterparty.

        The following table provides information about our derivative asset contract positions, net at December 31, 2013 (in thousands):

Derivative type
  Gross
derivative
assets
  Counterparty
liabilities netted
against assets
  Fair value of
derivative
assets, net
 

Bilateral over-the-counter contracts

  $ 54,119   $ (6,747 ) $ 47,372  

        The following table provides information about our derivative asset contract positions, net at December 31, 2012 (in thousands):

Derivative type
  Gross
derivative
assets
  Counterparty
liabilities netted
against assets
  Fair value of
derivative
assets, net
 

Bilateral over-the-counter contracts

  $ 22,868   $ (9,478 ) $ 13,390  

        The following table provides information about our derivative liability contract positions, net at December 31, 2013 (in thousands):

Derivative type
  Gross
derivative
liabilities
  Counterparty
assets netted
against liabilities
  Fair value of
derivative
liabilities, net
 

Bilateral over-the-counter contracts

  $ 36,870   $ (6,804 ) $ 30,066  

        The following table provides information about our derivative liability contract positions, net at December 31, 2012 (in thousands):

Derivative type
  Gross
derivative
liabilities
  Counterparty
assets netted
against liabilities
  Fair value of
derivative
liabilities, net
 

Bilateral over-the-counter contracts

  $ 21,425   $ (9,478 ) $ 11,947  

(7) BANK DEBT

TLP Credit Facility

        On March 9, 2011, TLP entered into an amended and restated senior secured credit facility, or the "TLP credit facility", which has been subsequently amended from time to time. The TLP credit facility

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(7) BANK DEBT (Continued)

provides for a maximum borrowing line of credit equal to the lesser of (i) $350 million and (ii) 4.75 times Consolidated EBITDA (as defined: $339.2 million at December 31, 2013). TLP may elect to have loans under the TLP credit facility that bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLP also pays a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.5% per annum, depending on the total leverage ratio then in effect. TLP's obligations under the TLP credit facility are secured by a first priority security interest in favor of the lenders in the majority of the TLP assets.

        The terms of the TLP credit facility include covenants that restrict TLP's ability to make cash distributions, acquisitions and investments, including investments in joint ventures. TLP may make distributions of cash to the extent of its "available cash" as defined in the TLP partnership agreement. TLP may make acquisitions and investments that meet the definition of "permitted acquisitions"; "other investments" which may not exceed 5% of "consolidated net tangible assets"; and "permitted JV investments". Permitted JV investments include up to $225 million of investments in BOSTCO, the "Specified BOSTCO Investment". In addition to the Specified BOSTCO Investment, under the terms of the TLP credit facility, TLP may make an additional $75 million of other permitted JV investments (including additional investments in BOSTCO). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 9, 2016.

        The following table summarizes the assets and liabilities of TLP at December 31, 2013 (in thousands):

Cash and cash equivalents

  $ 3,263  

Trade accounts receivable, net

    6,427  

Receivables from affiliates

    2,257  

Other current assets

    3,478  

Property, plant and equipment, net

    407,045  

Investments in unconsolidated affiliates

    211,605  

Other assets, net

    14,357  
       

Total assets

  $ 648,432  
       
       

Trade accounts payable

  $ 5,717  

Accrued liabilities

    16,189  

Long-term debt

    212,000  

Other noncurrent liabilities

    6,059  

Equity attributable to noncontrolling interests

    359,418  

Equity attributable to parent

    49,049  
       

Total liabilities and equity

  $ 648,432  
       
       

        The TLP credit facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the credit facility are (i) a total leverage ratio test (not to exceed 4.75 times), (ii) a senior

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(7) BANK DEBT (Continued)

secured leverage ratio test (not to exceed 3.75 times) in the event TLP issues senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times). If TLP were to fail any financial performance covenant, or any other covenant contained in the TLP credit facility, TLP would seek a waiver from its lenders under such facility. If TLP were unable to obtain a waiver from its lenders and the default remained uncured after any applicable grace period, TLP would be in breach of the TLP credit facility, and the lenders would be entitled to declare all outstanding borrowings immediately due and payable. TLP was in compliance with all of the financial covenants under the credit facility as of December 31, 2013.

        For the years ended December 31, 2013 and 2012, the weighted average interest rate on borrowings under the TLP credit facility was approximately 2.5% and 2.4%, respectively. At December 31, 2013 and 2012, TLP's outstanding borrowings under the TLP credit facility were $212 million and $184 million, respectively. At December 31, 2013 and 2012, TLP had no outstanding letters of credit.

        TLP has an effective universal shelf registration statement on Form S-3 with the Securities and Exchange Commission that expires in June 2016. TLP Finance Corp., a 100% owned subsidiary of TLP, may act as a co-issuer of any debt securities issued pursuant to that registration statement. TLP and TLP Finance Corp. have no independent assets or operations. TLP's operations are conducted by its subsidiaries, including its 100% owned operating company subsidiary, TransMontaigne Operating Company L.P. Each of TransMontaigne Operating Company L.P. and TLP's other 100% owned subsidiaries (other than TLP Finance Corp., whose sole purpose is to act as co-issuer of any debt securities) may guarantee the debt securities. TLP expects that any guarantees will be full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the indenture. There are no significant restrictions on the ability of TLP or any guarantor to obtain funds from its subsidiaries by dividend or loan. None of the assets of TLP or a guarantor represent restricted net assets pursuant to the guidelines established by the Securities and Exchange Commission.

TransMontaigne Credit Facility

        TransMontaigne has a senior secured working capital credit facility, or the "TransMontaigne credit facility" that provides for a maximum borrowing line of credit equal to the lesser of (i) $150 million or (ii) the borrowing base, which is a function of, among other things, restricted cash maintained in a specified account, accounts receivable, inventory and certain reserve adjustments as defined in the facility (as defined: $118.9 million at December 31, 2013). In addition, outstanding letters of credit are counted against the maximum borrowing capacity available at any time. Borrowings under the TransMontaigne credit facility bear interest (at TransMontaigne's option) based on a base rate plus an applicable margin, or LIBOR plus an applicable margin; the applicable margins range from 2% to 3% and are a function of the average excess borrowing base availability. In addition, TransMontaigne pays a commitment fee ranging from 0.50% to 0.625% per annum on the total amount of the unused commitments. Borrowings under the TransMontaigne credit facility are secured by the majority of the TransMontaigne's and its wholly-owned subsidiaries' assets, which excludes all TLP assets. The principal balance of loans and any accrued and unpaid interest is scheduled to be due and payable in full on the

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(7) BANK DEBT (Continued)

maturity date August 15, 2015. TransMontaigne primarily utilizes the facility to finance its crude oil marketing operations through the issuance of letters of credit to crude oil producers.

        For the years ended December 31, 2013 and 2012, the weighted average interest rate on letters of credit under the TransMontaigne credit facility was approximately 2.6% and 2.7%, respectively. At December 31, 2013 and 2012, TransMontaigne had no outstanding borrowings under the TransMontaigne credit facility. At December 31, 2013 and 2012, TransMontaigne's outstanding letters of credit were approximately $51.0 million and $52.5 million, respectively.

        In connection with the July 1, 2014 sale to NGL, and immediately prior thereto, the TransMontaigne credit facility was terminated.

(8) INCOME TAXES

        The Company's operating results have been included in the consolidated U.S. Federal and state income tax returns of Morgan Stanley. The amounts presented in the combined financial statements related to the Company's income taxes as determined as if the taxes were prepared on a separate tax return basis. Our separate return basis tax attributes may not reflect the tax positions taken or to be taken by Morgan Stanley. In many cases, the tax losses and other tax attributes of TransMontaigne have been utilized or are available to be utilized by Morgan Stanley, and may remain with Morgan Stanley after the separation of the Company from Morgan Stanley.

        Income tax (expense) benefit from continuing operations on a separate return basis consists of the following (in thousands):

 
  Years ended
December 31,
 
 
  2013   2012  

Current:

             

Federal income taxes

  $   $  

State income taxes

    (242 )   (188 )
           

Current income taxes

    (242 )   (188 )
           

Deferred:

             

Federal income taxes

         

State income taxes

         
           

Deferred income taxes

         
           

Income tax benefit (expense)

  $ (242 ) $ (188 )
           
           

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(8) INCOME TAXES (Continued)

        Income tax expense differs from the amount computed by applying the federal statutory corporate income tax rate of 35% to pretax earnings as a result of the following (in thousands):

 
  Years ended
December 31,
 
 
  2013   2012  

Computed "expected" tax benefit (expense)

  $ (13,117 ) $ 62,864  

Increase (reduction) in income taxes resulting from:

             

Nontaxable portion of NCI in TLP

    8,247     9,480  

Change in valuation allowance

    5,393     (80,754 )

State income taxes, net of federal income tax benefit

    (619 )   8,415  

Other, net

    (146 )   (193 )
           

Income tax benefit (expense)

  $ (242 ) $ (188 )
           
           

        The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows (in thousands):

 
  December 31,
2013
  December 31,
2012
 

Current deferred tax assets (liabilities):

             

Accrued liabilities, principally due to differences in accounting methods

  $ 5,184   $ 6,608  
           

Long-term deferred tax assets (liabilities):

             

Intangible assets, principally due to differences in amortization methods

  $ (1,159 ) $ (1,258 )

Investment in TransMontaigne Partners

    (29,271 )   (26,969 )

Intangible assets, principally due to differences in amortization methods and impairment allowances

    2,117     2,800  

Net operating losses

    85,019     84,776  

Plant and equipment, principally due to differences in depreciation methods

    (5,989 )   (4,663 )
           

Total long-term deferred tax assets

    50,717     54,686  
           

Valuation allowance

    (55,901 )   (61,294 )
           

Net deferred tax assets (liabilities)

  $   $  
           
           

        As of December 31, 2013 and 2012, TransMontaigne had no unrecognized tax benefits. There was no change in the amount of unrecognized tax benefits as a result of tax positions taken during the year or in prior periods or due to settlements with taxing authorities or lapses of applicable statutes of limitations. TransMontaigne is open to federal and state tax audits until the applicable statutes of limitations expire, including those applicable to Morgan Stanley. Tax audits are currently in process for several jurisdictions where TransMontaigne was part of the consolidated tax filings of Morgan Stanley. As a result, the statute of limitations is open for tax years since 2006. After consideration of tax losses made available to Morgan Stanley, TransMontaigne has state net operating loss carryforwards of $16.6 million and $9.6 million, respectively, which expire in the years 2015 to 2033, that will be

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(8) INCOME TAXES (Continued)

available to offset future taxable income after the Transaction. Due to the change in ownership of TransMontaigne, the net operating losses could be subject to certain limitations under Section 382 of the Internal Revenue Code of 1986, as amended.

        In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the expected timing of the reversal of taxable temporary differences and the realizability of the deferred tax assets on a separate return basis over the periods in which the deferred tax assets are deductible, the Company believes the "more likely than not" criterion has not been satisfied as of December 31, 2013 and 2012, and the benefits of future deductible differences have been fully valued.

(9) FAIR VALUE MEASUREMENTS

        Generally accepted accounting principles define fair value, establish a framework for measuring fair value and require disclosures about fair value measurements. Generally accepted accounting principles also establish a fair value hierarchy that maximizes the use of relevant observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels. The three levels of the fair value hierarchy are:

  Level 1       Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities and listed derivatives.

 

Level 2

 

 


 

Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

 

Level 3

 

 


 

Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management's best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

        The Company's inventory related assets and liabilities, its over-the-counter commodity purchase and sale derivative contracts and its variation margin payables are classified as Level 2 of the fair value hierarchy. The Company estimates fair values based on exchange quoted commodity prices, adjusted as appropriate for contract terms (including maturity) and differences in local markets. These differences are generally valued using inputs from broker or dealer quotations, published indices and consumer pricing services. The determination of the fair values for the derivative contracts and variation margin payables also factor the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit, and priority interests), and also the impact of the

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(9) FAIR VALUE MEASUREMENTS (Continued)

Company's nonperformance risk on its liabilities. The Company is able to classify these fair value balances based on the observability of inputs.

        The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012.

 
  December 31, 2013  
 
  Level 1   Level 2   Level 3   Total  

Assets carried at fair value (in thousands):

                         

Inventories in pipelines and terminals

  $   $ 629,567   $   $ 629,567  

Inventories in transit via truck and rail

        53,216         53,216  

Derivative contracts

        47,372         47,372  

Liabilities carried at fair value (in thousands):

                         

Inventories due under exchange agreements

        31,280         31,280  

Derivative contracts

        30,066         30,066  

Variation margin payables

        35,528         35,528  

 

 
  December 31, 2012  
 
  Level 1   Level 2   Level 3   Total  

Assets carried at fair value (in thousands):

                         

Inventories in pipelines and terminals

  $   $ 660,044   $   $ 660,044  

Inventories in transit via truck and rail

        59,703         59,703  

Derivative contracts

        13,390         13,390  

Liabilities carried at fair value (in thousands):

                         

Inventories due under exchange agreements

        35,343         35,343  

Derivative contracts

        11,947         11,947  

Variation margin payables

        30,633         30,633  

        The Company also has financial instruments that are not accounted for at fair value, which generally accepted accounting principles require we disclose the fair value. The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that constitute financial instruments and were not accounted for at fair value as of December 31, 2013 and 2012. We believe the carrying amounts of these financial instruments reasonably approximate their fair values due

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(9) FAIR VALUE MEASUREMENTS (Continued)

to their short-term nature, and in the case of our bank debt due to the borrowings bearing interest at current market interest rates.

 
  December 31, 2013  
 
  Level 1   Level 2   Level 3   Total  

Assets for which the carrying value approximates fair value (in thousands):

                         

Cash and cash equivalents

  $ 74,762   $   $   $ 74,762  

Rack sales accounts receivable, net

        243,520         243,520  

Pipeline sales accounts receivable

        684,881         684,881  

Other pipeline accrued receivables

        6,123         6,123  

Other current assets—restricted cash

    1,000             1,000  

Liabilities for which the carrying value approximates fair value (in thousands)

                         

Accounts payable

        64,351         64,351  

Product purchases accounts payable

        785,112         785,112  

Excise taxes payable

        39,648         39,648  

Other pipeline accrued payables

        20,589         20,589  

Bank debt

        212,000         212,000  

 

 
  December 31, 2012  
 
  Level 1   Level 2   Level 3   Total  

Assets for which the carrying value approximates fair value (in thousands):

                         

Cash and cash equivalents

  $ 15,156   $   $   $ 15,156  

Rack sales accounts receivable, net

        307,757         307,757  

Pipeline sales accounts receivable

        520,944         520,944  

Other pipeline accrued receivables

        2,808         2,808  

Other current assets—restricted cash

    1,120             1,120  

Liabilities for which the carrying value approximates fair value (in thousands)

                         

Accounts payable

        100,651         100,651  

Product purchases accounts payable

        705,863         705,863  

Excise taxes payable

        55,139         55,139  

Other pipeline accrued payables

        18,953         18,953  

Bank debt

        184,000         184,000  

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(10) COMMITMENTS AND CONTINGENCIES

        At December 31, 2013, future minimum lease payments under our non-cancelable operating leases are as follows (in thousands):

Years ending December 31:
  Office
space
  Rail cars   Property
and
equipment
  Total  

2014

  $ 2,049   $ 1,960   $ 3,753   $ 7,762  

2015

    2,104     408     3,920     6,432  

2016

    2,159     238     3,997     6,394  

2017

    2,150         2,989     5,139  

2018

    1,412         588     2,000  

Thereafter

    1,192         3,891     5,083  
                   

  $ 11,066   $ 2,606   $ 19,138   $ 32,810  
                   
                   

        Rental expense under operating leases is as follows (in thousands):

 
  Years ended December 31,  
 
  2013   2012  

Office space

  $ 1,772   $ 1,870  

Rail cars

    6,887     2,288  

Property and equipment

    3,573     1,471  
           

  $ 12,232   $ 5,629  
           
           

(11) SUBSEQUENT EVENTS

        We have evaluated subsequent events through November 5, 2014, which is the date the financial statements were available to be issued, except for Note 12, as to which we have evaluated subsequent events through December 24, 2014.

        On July 1, 2014, Morgan Stanley consummated the sale of its indirect 100% ownership interest in TransMontaigne Inc. to NGL. TransMontaigne Inc. is the indirect parent and sole member of TransMontaigne GP L.L.C., which is the sole general partner of TLP, a publically traded master limited partnership. The sale also included Morgan Stanley's limited partnership interests in TLP, the assignment from an affiliate of Morgan Stanley to NGL of certain terminaling services agreements with TLP, and the transfer of certain inventory owned by Morgan Stanley.

        In connection with the July 1, 2014 sale to NGL, and immediately prior thereto, the TransMontaigne credit facility was terminated.

(12) Condensed Consolidating Guarantor and Non-Guarantor Financial Information

        Subsequent to the July 2014 acquisition of the Company by NGL, TransMontaigne Inc. and certain of its subsidiaries became guarantors of certain of NGL's notes, and the other assets and operations acquired from Morgan Stanley were placed into a subsidiary of NGL that also guarantee these notes. As a result, this activity is presented in the guarantor column in the condensed consolidating tables below. TLP and its subsidiaries are not guarantors of these notes. Pursuant to Rule 3-10 of

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(12) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Regulation S-X, certain historical financial data of the Company is shown below, with the operations of TLP shown separately from the other assets and operations of the Company. Under TLP's credit agreement, TLP may make distributions of cash to the extent of its "available cash" as defined in TLP's partnership agreement. There are no significant restrictions upon the ability of the parent or any of the guarantor subsidiaries to obtain funds from their other respective subsidiaries by dividend or loan. NGL is the parent entity of the guarantors of NGL's notes, and NGL is not part of these combined financial statements; as a result, no parent entity activity is shown in the condensed consolidating tables below.

Combining balance sheet at December 31, 2013

 
  December 31, 2013  
 
  Guarantor
Entities
  Non-Guarantor
Entities
  Combining
Adjustments
  Combined  
 
  (in thousands)
 

ASSETS

                         

Current assets:

                         

Cash and cash equivalents

  $ 71,499   $ 3,263   $   $ 74,762  

Rack sales accounts receivable, net

    238,924     6,612     (2,016 )   243,520  

Pipeline sales accounts receivable

    684,881             684,881  

Inventories in pipelines and terminals

    629,567             629,567  

Inventories in transit via truck and rail

    53,216             53,216  

Derivative contracts

    47,372             47,372  

Other pipeline accrued receivables

    6,123             6,123  

Intercompany receivables

        2,072     (2,072 )    

Other

    24,596     3,478     (10,526 )   17,548  
                   

    1,756,178     15,425     (14,614 )   1,756,989  

Property, plant and equipment, net

    38,450     407,045         445,495  

Investment in non-guarantor entities

    49,049         (49,049 )    

Investment in unconsolidated affiliates

        211,605         211,605  

Other assets

    6,146     14,357     (2,146 )   18,357  
                   

  $ 1,849,823   $ 648,432   $ (65,809 ) $ 2,432,446  
                   
                   

LIABILITIES AND EQUITY

                         

Current liabilities:

                         

Accounts payable

  $ 58,634   $ 5,717   $   $ 64,351  

Product purchases accounts payable

    785,112             785,112  

Excise taxes payable

    39,648             39,648  

Inventories due under exchange agreements

    31,280             31,280  

Derivative contracts

    30,066             30,066  

Accrued environmental obligations

    4,303             4,303  

Variation margin payables

    35,528             35,528  

Other pipeline accrued payables

    20,589             20,589  

Intercompany payables

    2,072         (2,072 )    

Other accrued liabilities

    21,543     16,189     (14,469 )   23,263  
                   

    1,028,775     21,906     (16,541 )   1,034,140  

Bank debt

        212,000         212,000  

Other

    3,522     6,059     (219 )   9,362  
                   

Total liabilities

    1,032,297     239,965     (16,760 )   1,255,502  
                   

Equity:

                         

Equity attributable to noncontrolling interests

        359,418         359,418  

Equity attributable to parent

    817,526     49,049     (49,049 )   817,526  
                   

    817,526     408,467     (49,049 )   1,176,944  
                   

  $ 1,849,823   $ 648,432   $ (65,809 ) $ 2,432,446  
                   
                   

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(12) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Combining balance sheet at December 31, 2012

 
  Guarantor
Entities
  Non-Guarantor
Entities
  Combining
Adjustments
  Combined  
 
  (in thousands)
 

ASSETS

                         

Current assets:

                         

Cash and cash equivalents

  $ 8,411   $ 6,745   $   $ 15,156  

Rack sales accounts receivable, net

    302,535     5,222         307,757  

Pipeline sales accounts receivable

    520,944             520,944  

Inventories in pipelines and terminals

    660,044             660,044  

Inventories in transit via truck and rail          

    59,703             59,703  

Derivative contracts

    13,390             13,390  

Other pipeline accrued receivables

    2,808             2,808  

Intercompany receivables

        2,848     (2,848 )    

Other

    17,860     4,579     (7,372 )   15,067  
                   

    1,585,695     19,394     (10,220 )   1,594,869  

Property, plant and equipment, net

    39,486     427,701         467,187  

Investment in non-guarantor entities

    49,532         (49,532 )    

Investment in unconsolidated affiliates

        105,164         105,164  

Other assets

    5,575     17,542     (3,648 )   19,469  
                   

  $ 1,680,288   $ 569,801   $ (63,400 ) $ 2,186,689  
                   
                   

LIABILITIES AND EQUITY

                         

Current liabilities:

                         

Accounts payable

  $ 89,841   $ 10,810   $   $ 100,651  

Product purchases accounts payable

    705,863             705,863  

Excise taxes payable

    55,139             55,139  

Inventories due under exchange agreements

    35,343             35,343  

Derivative contracts

    11,947             11,947  

Accrued environmental obligations

    6,215             6,215  

Variation margin payables

    30,633             30,633  

Other pipeline accrued payables

    18,953             18,953  

Intercompany payables

    2,848         (2,848 )    

Other accrued liabilities

    23,349     15,606     (11,020 )   27,935  
                   

    980,131     26,416     (13,868 )   992,679  

Bank debt

        184,000         184,000  

Other

    1,247     10,648         11,895  
                   

Total liabilities

    981,378     221,064     (13,868 )   1,188,574  
                   

Equity:

                         

Equity attributable to noncontrolling interests

        299,205         299,205  

Equity attributable to parent

    698,910     49,532     (49,532 )   698,910  
                   

    698,910     348,737     (49,532 )   998,115  
                   

  $ 1,680,288   $ 569,801   $ (63,400 ) $ 2,186,689  
                   
                   

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(12) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Combining statements of operations and comprehensive income for the year ended December 31, 2013

 
  Guarantor
Entities
  Non-Guarantor
Entities
  Combining
Adjustments
  Combined  
 
  (in thousands)
 

Marketing and distribution:

                         

Revenues

  $ 8,579,362   $   $   $ 8,579,362  

Cost of product sold and other direct costs and expenses

    (8,526,753 )       63,033     (8,463,720 )
                   

Net operating margins, exclusive of depreciation and amortization shown separately below

    52,609         63,033     115,642  
                   

Terminals and pipelines:

                         

Revenues

    2,067     158,886     (101,109 )   59,844  

Direct costs and expenses

    1,900     (69,390 )   38,076     (29,414 )
                   

Net operating margins, exclusive of depreciation and amortization shown separately below

    3,967     89,496     (63,033 )   30,430  
                   

Total net operating margins

    56,576     89,496         146,072  
                   

Costs and expenses:

                         

Selling, general, and administrative

    (45,132 )   (19,887 )       (65,019 )

Depreciation and amortization

    (4,693 )   (29,568 )       (34,261 )

Loss on disposition of assets, net

    (728 )   (1,294 )       (2,022 )

Loss from unconsolidated affiliates

        (321 )       (321 )
                   

Total costs and expenses

    (50,553 )   (51,070 )       (101,623 )
                   

Operating income

    6,023     38,426         44,449  
                   

Other income (expenses):

                         

Equity in earnings of non-guarantor entities

    11,136         (11,136 )    

Interest expense

    (2,287 )   (3,687 )       (5,974 )

Foreign currency transaction loss

        (13 )       (13 )
                   

Total other income (expenses)

    8,849     (3,700 )   (11,136 )   (5,987 )
                   

Earnings before income taxes

    14,872     34,726     (11,136 )   38,462  

Income tax expense

    (242 )           (242 )
                   

Net income

    14,630     34,726     (11,136 )   38,220  

Noncontrolling interests share in earnings of TransMontaigne Partners

        (23,590 )       (23,590 )
                   

Net income attributable to parent

    14,630     11,136     (11,136 )   14,630  

Other comprehensive income—foreign currency translation adjustments attributable to noncontrolling interests

        56         56  

Other comprehensive income—foreign currency translation adjustments attributable to parent

        27         27  
                   

Comprehensive income

  $ 14,630   $ 11,219   $ (11,136 ) $ 14,713  
                   
                   

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(12) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Combining statements of operations and comprehensive income (loss) for the year ended December 31, 2012

 
  Year Ended December 31, 2012  
 
  Guarantor
Entities
  Non-Guarantor
Entities
  Combining
Adjustments
  Combined  
 
  (in thousands)
 

Marketing and distribution:

                         

Revenues

  $ 10,877,459   $   $   $ 10,877,459  

Cost of product sold and other direct costs and expenses

    (11,047,081 )       63,733     (10,983,348 )
                   

Net operating margin loss, exclusive of depreciation and amortization shown separately below

    (169,622 )       63,733     (105,889 )
                   

Terminals and pipelines:

                         

Revenues

    3,521     156,239     (107,045 )   52,715  

Direct costs and expenses

    1,418     (65,964 )   43,312     (21,234 )
                   

Net operating margins, exclusive of depreciation and amortization shown separately below

    4,939     90,275     (63,733 )   31,481  
                   

Total net operating margins (loss)

    (164,683 )   90,275         (74,408 )
                   

Costs and expenses:

                         

Selling, general, and administrative

    (47,541 )   (20,430 )       (67,971 )

Depreciation and amortization

    (4,007 )   (28,260 )       (32,267 )

Gain on disposition of assets, net          

    856             856  

Earnings from unconsolidated affiliates

        558         558  
                   

Total costs and expenses

    (50,692 )   (48,132 )       (98,824 )
                   

Operating income (loss)

    (215,375 )   42,143         (173,232 )
                   

Other income (expenses):

                         

Equity in earnings of non-guarantor entities

    11,486         (11,486 )    

Interest expense

    (2,927 )   (3,622 )       (6,549 )

Foreign currency transaction gain

        51         51  
                   

Total other income (expenses)          

    8,559     (3,571 )   (11,486 )   (6,498 )
                   

Earnings (loss) before income taxes

    (206,816 )   38,572     (11,486 )   (179,730 )

Income tax expense

    (188 )           (188 )
                   

Net income (loss)

    (207,004 )   38,572     (11,486 )   (179,918 )

Noncontrolling interests share in earnings of TransMontaigne Partners

        (27,086 )       (27,086 )
                   

Net income (loss) attributable to parent

    (207,004 )   11,486     (11,486 )   (207,004 )

Other comprehensive income—foreign currency translation adjustments attributable to noncontrolling interests

        128         128  

Other comprehensive income—foreign currency translation adjustments attributable to parent

        63         63  
                   

Comprehensive income (loss)

  $ (207,004 ) $ 11,677   $ (11,486 ) $ (206,813 )
                   
                   

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(12) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining statements of cash flows for the year ended December 31, 2013

 
  Guarantor
Entities
  Non-Guarantor
Entities
  Combined  
 
  (in thousands)
 

Net cash provided by (used in) operating activities

  $ (49,183 ) $ 64,235   $ 15,052  

Cash flows from investing activities:

   
 
   
 
   
 
 

Investments in unconsolidated affiliates

        (108,229 )   (108,229 )

Capital expenditures

    (3,567 )   (13,838 )   (17,405 )

Proceeds from sale of assets

    185     2,109     2,294  
               

Net cash used in investing activities

    (3,382 )   (119,958 )   (123,340 )
               

Cash flows from financing activities:

                   

Proceeds from issuance of TransMontaigne Partners' common units

        68,774     68,774  

Borrowings of bank debt

        168,500     168,500  

Repayments of bank debt

        (140,500 )   (140,500 )

Net capital contributed by (distributed to) affiliated entities          

    115,403     (11,578 )   103,825  

Distributions paid to noncontrolling TransMontaigne Partners' common units

        (32,419 )   (32,419 )

Purchase of common units by TransMontaigne Partners' long-term incentive plan

    250     (585 )   (335 )
               

Net cash provided by financing activities

    115,653     52,192     167,845  
               

Increase (decrease) in cash and cash equivalents

    63,088     (3,531 )   59,557  

Foreign currency translation effect on cash

        49     49  
               

Cash and cash equivalents at beginning of period

    8,411     6,745     15,156  
               

Cash and cash equivalents at end of period

  $ 71,499   $ 3,263   $ 74,762  
               
               

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(12) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining statements of cash flows for the year ended December 31, 2012

 
  Guarantor
Entities
  Non-Guarantor
Entities
  Combined  
 
  (in thousands)
 

Net cash provided by operating activities

  $ 301,677   $ 64,311   $ 365,988  

Cash flows from investing activities:

   
 
   
 
   
 
 

Investments in unconsolidated affiliates

        (80,166 )   (80,166 )

Capital expenditures

    (7,613 )   (23,565 )   (31,178 )

Proceeds from sale of assets

    1,086     18,000     19,086  
               

Net cash used in investing activities

    (6,527 )   (85,731 )   (92,258 )
               

Cash flows from financing activities:

                   

Borrowings of bank debt

        147,000     147,000  

Repayments of bank debt

        (83,000 )   (83,000 )

Deferred debt issuance costs

        (736 )   (736 )

Net capital distributed to affiliated entities

    (363,032 )   (12,045 )   (375,077 )

Distributions paid to noncontrolling TransMontaigne Partners' common units

        (29,801 )   (29,801 )

Purchase of common units by TransMontaigne Partners' long-term incentive plan

    215     (454 )   (239 )
               

Net cash provided by (used in) financing activities

    (362,817 )   20,964     (341,853 )
               

Decrease in cash and cash equivalents

    (67,667 )   (456 )   (68,123 )

Foreign currency translation effect on cash

        63     63  
               

Cash and cash equivalents at beginning of period

    76,078     7,138     83,216  
               

Cash and cash equivalents at end of period

  $ 8,411   $ 6,745   $ 15,156  
               
               

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Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners

Condensed Combined Balance Sheets

(Unaudited and in thousands)

 
  June 30, 2014   December 31, 2013  

ASSETS

             

Current assets:

             

Cash and cash equivalents

  $ 71,549   $ 74,762  

Rack sales accounts receivable, net

    198,702     243,520  

Pipeline sales accounts receivable

    202,795     684,881  

Inventories in pipelines and terminals

    542,187     629,567  

Inventories in transit via truck and rail

    44,844     53,216  

Derivative contracts

    6,375     47,372  

Other pipeline accrued receivables

    3,803     6,123  

Other

    38,551     17,548  
           

    1,108,806     1,756,989  

Property, plant and equipment, net

    431,486     445,495  

Investment in unconsolidated affiliates

    234,002     211,605  

Other assets

    16,676     18,357  
           

  $ 1,790,970   $ 2,432,446  
           
           

LIABILITIES AND EQUITY

             

Current liabilities:

             

Accounts payable

  $ 120,656   $ 64,351  

Product purchases accounts payable

    229,363     785,112  

Excise taxes payable

    28,324     39,648  

Inventories due under exchange agreements

    5,788     31,280  

Derivative contracts

    7,765     30,066  

Accrued environmental obligations

    4,208     4,303  

Variation margin payables

    16,888     35,528  

Other pipeline accrued payables

    12,813     20,589  

Other accrued liabilities

    35,320     23,263  
           

    461,125     1,034,140  

Bank debt

    234,000     212,000  

Other

    4,491     9,362  
           

Total liabilities

    699,616     1,255,502  
           

Equity:

             

Equity attributable to noncontrolling interests

    355,624     359,418  

Equity attributable to parent

    735,730     817,526  
           

    1,091,354     1,176,944  
           

  $ 1,790,970   $ 2,432,446  
           
           

   

See accompanying notes to condensed combined financial statements.

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Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP

Condensed Combined Statements of Comprehensive Loss

(Unaudited and in thousands)

 
  Six months ended June 30, 2014   Six months ended June 30, 2013  

Marketing and distribution:

             

Revenues

  $ 4,000,573   $ 4,678,070  

Cost of product sold and other direct costs and expenses

    (3,948,828 )   (4,648,787 )
           

Net operating margins, exclusive of depreciation and amortization shown separately below

    51,745     29,283  
           

Terminals and pipelines:

             

Revenues

    33,650     31,537  

Direct costs and expenses

    (16,833 )   (15,075 )
           

Net operating margins, exclusive of depreciation and amortization shown separately below

    16,817     16,462  
           

Total net operating margins

    68,562     45,745  
           

Costs and expenses:

             

Selling, general and administrative

    (41,166 )   (32,060 )

Depreciation and amortization

    (17,346 )   (17,018 )

Gain (loss) on disposition of assets, net

    98     (845 )

Earnings from unconsolidated affiliates

    1,438     36  
           

Total costs and expenses

    (56,976 )   (49,887 )
           

Operating income (loss)

    11,586     (4,142 )
           

Other income (expenses):

             

Interest expense

    (3,065 )   (2,625 )

Amortization of deferred financing costs

    (687 )   (687 )

Foreign currency transaction loss

        (8 )
           

Total other expenses

    (3,752 )   (3,320 )
           

Earnings (loss) before income taxes

    7,834     (7,462 )

Income tax expense

    (302 )   (102 )
           

Net income

    7,532     (7,564 )

Noncontrolling interests share in earnings of TransMontaigne Partners

    (13,677 )   (13,759 )
           

Net loss attributable to parent

    (6,145 )   (21,323 )

Other comprehensive income—foreign currency translation adjustments attributable to noncontrolling interests

        2  
           

Comprehensive loss

  $ (6,145 ) $ (21,321 )
           
           

   

See accompanying notes to condensed combined financial statements.

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Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP

Condensed Combined Statement of Equity

Six months ended June 30, 2014

(Unaudited and in thousands)

 
  Equity attributable to noncontrolling interests   Equity attributable to Parent, Net   Total equity  

Balance at December 31, 2013

  $ 359,418   $ 817,526   $ 1,176,944  

Distributions paid to non-controlling TransMontaigne Partners' common units

    (17,408 )       (17,408 )

Purchase of common units by TransMontaigne Partners' long-term incentive plan

    (177 )       (177 )

Deferred equity-based compensation related to restricted phantom units and other

    114         114  

Net income (loss)

    13,677     (6,145 )   7,532  

Net capital distributed to parent company

        (75,651 )   (75,651 )
               

Balance at June 30, 2014

  $ 355,624   $ 735,730   $ 1,091,354  
               
               

   

See accompanying notes to condensed combined financial statements.

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Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP

Condensed Combined Statements of Cash Flows

(Unaudited and in thousands)

 
  Six months ended June 30, 2014   Six months ended June 30, 2013  

Net cash provided by (used in) operating activities

  $ 94,190   $ (98,771 )
           

Cash flows from investing activities:

             

Investments in unconsolidated affiliates

    (23,397 )   (70,956 )

Capital expenditures

    (3,755 )   (12,912 )

Proceeds from sale of assets

    1     89  
           

Net cash used in investing activities

    (27,151 )   (83,779 )
           

Cash flows from financing activities:

             

Borrowings of bank debt

    56,000     119,500  

Repayments of bank debt

    (34,000 )   (49,500 )

Net capital contributed by (distributed to) parent company

    (74,667 )   185,059  

Distributions paid to non-controlling TransMontaigne Partners' common units

    (17,408 )   (15,016 )

Purchase of common units by TransMontaigne Partners' long-term incentive plan

    (177 )   (166 )

Other

        (398 )
           

Net cash provided by (used in) financing activities

    (70,252 )   239,479  
           

Increase (decrease) in cash and cash equivalents

    (3,213 )   56,929  

Foreign currency translation effect on cash

        46  
           

Cash and cash equivalents at beginning of period

    74,762     15,156  
           

Cash and cash equivalents at end of period

  $ 71,549   $ 72,131  

Supplemental disclosures of cash flow information:

             

Cash paid for interest

  $ 3,140   $ 2,426  
           
           

Property, plant and equipment acquired with accounts payable

  $ 75   $ 246  
           
           

   

See accompanying notes to condensed combined financial statements.

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Notes to Condensed Combined Financial Statements

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a)    Nature of business

        The accompanying combined interim financial statements include the accounts of all operations of the Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP (collectively, the "Company", "we", "us" or "our"). On July 1, 2014, Morgan Stanley consummated the sale of its indirect 100% ownership interest in the Business to NGL Energy Partners LP ("NGL"). TransMontaigne Inc. is the indirect parent and sole member of TransMontaigne GP L.L.C., which is the sole general partner ("General Partner") of TransMontaigne Partners L.P. ("TLP" or the "Partnership"), a publicly traded master limited partnership. The sale also included Morgan Stanley's limited partnership interests in TLP, the assignment from an affiliate of Morgan Stanley to NGL of certain terminaling services agreements with TLP, and the transfer of certain inventory owned by Morgan Stanley (collectively, the "Transaction"). The Transaction does not involve the sale or purchase of any of the limited partnership units in TLP held by the public and the TLP limited partnership units continue to trade on the New York Stock Exchange.

        TransMontaigne Inc., ("TransMontaigne") is a Delaware corporation headquartered in Denver, Colorado, that was formed in 1995 as a refined petroleum products marketing and distribution company. TransMontaigne and its wholly-owned subsidiaries conduct operations in the United States primarily in the Southeast, Florida, and Midwest regions. TransMontaigne primarily provides integrated marketing and distribution services to end-users of refined petroleum products and, to a lesser extent, users of crude oil and renewable fuels.

        TransMontaigne's less than wholly-owned subsidiary includes the publicly traded master limited partnership of TLP. TLP was formed in February 2005 as a Delaware limited partnership to own and operate refined petroleum products terminaling and transportation facilities. TLP conducts its operations in the United States along the Gulf Coast, in the Midwest, in Houston and Brownsville, Texas, along the Mississippi and Ohio rivers and in the Southeast. TLP provides integrated terminaling, storage, transportation and related services for companies engaged in the trading, distribution and marketing of light refined petroleum products, heavy refined petroleum products, crude oil, chemicals, fertilizers and other liquid products. TransMontaigne and NGL, subsequent to the Transaction, have an interest in TLP through the ownership of approximately 20% of the limited partner interests, a 2% general partner interest and the incentive distribution rights.

(b)    Basis of presentation and use of estimates

        In preparing the accompanying unaudited condensed combined financial statements, we have followed the accounting policies of Morgan Stanley, a broker-dealer, and TransMontaigne Inc., which are in accordance with United States generally accepted accounting principles or "GAAP" for interim financial information. Accordingly, the unaudited condensed combined financial statements do not include all the information and notes required by GAAP for complete annual financial statements. However, we believe that the disclosures made are adequate to make the information not misleading. The combined financial statements of the Company have been prepared from the separate records maintained by Morgan Stanley and TransMontaigne Inc. and may not necessarily be indicative of the conditions that would have existed, or the results of operations, if the Company had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various assets

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

comprising the Company, Morgan Stanley's net investment in the Company is shown as net parent equity, in lieu of owner's equity, in the combined financial statements. All intercompany balances have been eliminated. Transactions between us and Morgan Stanley operations have been identified in the combined financial statements as transactions between affiliates. In the opinion of management, all adjustments have been reflected that are necessary for a fair presentation of the combined financial statements.

        The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The following estimates, in our opinion, are subjective in nature and require the exercise of judgment: allowance for doubtful accounts; fair value of inventories; fair value of derivative contracts; useful lives of our plant and equipment; and accrued environmental obligations. Changes in these estimates and assumptions will occur as a result of the passage of time and the occurrence of future events. Actual results could differ from these estimates.

(c)    Significant accounting policies

        The Company's significant accounting policies are consistent with those disclosed in Note 1 of the Company's audited combined financial statements for the years ended December 31, 2013 and 2012.

(2) INVENTORIES

        Our inventories are carried at fair value, and the classes of inventories are as follows (amounts and volume of barrels in thousands):

Inventories in pipelines and terminals:

 
  June 30, 2014   December 31, 2013  
 
  Amount   Barrels   Amount   Barrels  

Gasoline

  $ 306,119     2,477   $ 400,120     3,618  

Distillate

    218,843     1,758     220,702     1,736  

Ethanol

    17,196     228     7,946     98  

Crude oil

            799     8  

Other

    29     2          
                   

  $ 542,187     4,465   $ 629,567     5,460  
                   
                   

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(2) INVENTORIES (Continued)

Inventories in transit via truck and rail:

 
  June 30, 2014   December 31, 2013  
 
  Amount   Barrels   Amount   Barrels  

Gasoline

  $       $ 16,725     176  

Distillate

    15,680     127     13,516     111  

Ethanol

    7,554     87     17,193     218  

Crude oil

    21,610     208     5,782     59  
                   

  $ 44,844     422   $ 53,216     564  
                   
                   

(3) PROPERTY, PLANT AND EQUIPMENT

        Property, plant and equipment, net is as follows (in thousands):

 
   
   
  June 30, 2014   December 31, 2013  

Land

  $ 57,568   $ 57,568  

Terminals, pipelines and equipment

    603,812     601,921  

Furniture, fixtures and equipment

    21,366     20,941  

Construction in progress

    4,487     3,691  
                       

                687,233     684,121  

Less accumulated depreciation

    (255,747 )   (238,626 )
                       

              $ 431,486   $ 445,495  
                       
                       

(4) DERIVATIVE CONTRACTS

        The Company purchases and sells commodities, such as gasoline, distillate, ethanol and crude oil. The Company generally follows a policy of using over-the-counter commodity derivatives as components of market strategies designed to enhance margins. The results of these strategies can be significantly impacted by factors such as the volatility of the relationship between the value of commodity derivatives and the prices of the underlying commodities, counterparty contract defaults, and volatility of transportation markets.

        The majority of the Company's commodity purchase and sales contracts qualify as over-the-counter derivative instruments and the change in fair value is reported in cost of product sold within the marketing and distribution section of the accompanying combined interim statements of comprehensive income (loss). Changes in the fair value of our derivatives are recognized in earnings. The Company reports the fair value of its over-the-counter derivative assets and liabilities on the combined balance sheets as derivative contract assets and liabilities.

        The Company has established guidelines to manage and mitigate credit risk within risk tolerances. The Company attempts to mitigate its credit exposure by setting tenor and credit limits commensurate with counterparty financial strength and obtaining master netting agreements. The use of master

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(4) DERIVATIVE CONTRACTS (Continued)

netting agreements is driven by industry practice, and anticipated volumes and complexity of the business relationship with the counterparty.

        The following table provides information about our derivative asset contract positions, net at June 30, 2014 (in thousands):

Derivative type
  Gross derivative assets   Counterparty liabilities netted against assets   Fair value of derivative assets, net  

Bilateral over-the-counter contracts

  $ 11,099   $ (4,724 ) $ 6,375  

        The following table provides information about our derivative asset contract positions, net at December 31, 2013 (in thousands):

Derivative type
  Gross derivative assets   Counterparty liabilities netted against assets   Fair value of derivative assets, net  

Bilateral over-the-counter contracts

  $ 54,119   $ (6,747 ) $ 47,372  

        The following table provides information about our derivative liability contract positions, net at June 30, 2014 (in thousands):

Derivative type
  Gross derivative liabilities   Counterparty assets netted against liabilities   Fair value of derivative liabilities, net  

Bilateral over-the-counter contracts

  $ 12,460   $ (4,695 ) $ 7,765  

        The following table provides information about our derivative liability contract positions, net at December 31, 2013 (in thousands):

Derivative type
  Gross derivative liabilities   Counterparty assets netted against liabilities   Fair value of derivative liabilities, net  

Bilateral over-the-counter contracts

  $ 36,870   $ (6,804 ) $ 30,066  

(5) BANK DEBT

TLP Credit Facility

        On March 9, 2011, TLP entered into an amended and restated senior secured credit facility, or the "TLP credit facility", which has been subsequently amended from time to time. The TLP credit facility provides for a maximum borrowing line of credit equal to the lesser of (i) $350 million and (ii) 4.75 times Consolidated EBITDA (as defined $345.7 million at June 30, 2014). TLP may elect to have loans under the TLP credit facility that bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLP also pays a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.5% per annum, depending on the total leverage ratio then in effect. TLP's obligations under the TLP credit facility are secured by a first priority security interest in favor of the lenders in the majority of the TLP assets.

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(5) BANK DEBT (Continued)

        The terms of the TLP credit facility include covenants that restrict TLP's ability to make cash distributions, acquisitions and investments, including investments in joint ventures. TLP may make distributions of cash to the extent of its "available cash" as defined in the TLP partnership agreement. TLP may make acquisitions and investments that meet the definition of "permitted acquisitions"; "other investments" which may not exceed 5% of "consolidated net tangible assets"; and "permitted JV investments". Permitted JV investments include up to $225 million of investments in Battleground Oil Specialty Terminal Company LLC ("BOSTCO"), the "Specified BOSTCO Investment". In addition to the Specified BOSTCO Investment, under the terms of the TLP credit facility, TLP may make an additional $75 million of other permitted JV investments (including additional investments in BOSTCO). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 9, 2016.

        The TLP credit facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the credit facility are (i) a total leverage ratio test (not to exceed 4.75 times), (ii) a senior secured leverage ratio test (not to exceed 3.75 times) in the event TLP issues senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times). If TLP were to fail any financial performance covenant, or any other covenant contained in the TLP credit facility, TLP would seek a waiver from its lenders under such facility. If TLP were unable to obtain a waiver from its lenders and the default remained uncured after any applicable grace period, TLP would be in breach of the TLP credit facility, and the lenders would be entitled to declare all outstanding borrowings immediately due and payable. TLP was in compliance with all of the financial covenants under the credit facility as of June 30, 2014.

        At June 30, 2014 and December 31, 2013, TLP's outstanding borrowings under the TLP credit facility were $234 million and $212 million, respectively. At June 30, 2014 and December 31, 2013, TLP had no outstanding letters of credit.

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(5) BANK DEBT (Continued)

        The following table summarizes the assets and liabilities of TLP at June 30, 2014 (in thousands):

Cash and cash equivalents

  $ 1,469  

Trade accounts receivable, net

    8,638  

Receivables from affiliates

    3,449  

Other current assets

    3,249  

Property, plant and equipment, net

    394,319  

Investments in unconsolidated affiliates

    234,002  

Other assets, net

    13,167  
       

Total assets

  $ 658,293  
       
       

Trade accounts payable

  $ 4,868  

Accrued liabilities

    10,788  

Long-term debt

    234,000  

Other noncurrent liabilities

    4,753  

Equity attributable to noncontrolling interests

    355,624  

Equity attributable to parent

    48,260  
       

Total liabilities and equity

  $ 658,293  
       
       

TransMontaigne Credit Facility

        TransMontaigne has a senior secured working capital credit facility, or the "TransMontaigne credit facility" that provides for a maximum borrowing line of credit equal to the lesser of (i) $150 million or (ii) the borrowing base, which is a function of, among other things, restricted cash maintained in a specified account, accounts receivable, inventory and certain reserve adjustments as defined in the facility (as defined: $103.2 million at June 30, 2014). In addition, outstanding letters of credit are counted against the maximum borrowing capacity available at any time. Borrowings under the TransMontaigne credit facility bear interest (at TransMontaigne's option) based on a base rate plus an applicable margin, or LIBOR plus an applicable margin; the applicable margins range from 2% to 3% and are a function of the average excess borrowing base availability. In addition, TransMontaigne pays a commitment fee ranging from 0.50% to 0.625% per annum on the total amount of the unused commitments. Borrowings under the TransMontaigne credit facility are secured by the majority of the TransMontaigne's and its wholly-owned subsidiaries' assets, which excludes all TLP assets. The principal balance of loans and any accrued and unpaid interest is scheduled to be due and payable in full on the maturity date August 15, 2015. TransMontaigne primarily utilizes the facility to finance its crude oil marketing operations through the issuance of letters of credit to crude oil producers.

        At June 30, 2014 and December 31, 2013, TransMontaigne had no outstanding borrowings under the TransMontaigne credit facility. At June 30, 2014 and December 31, 2013, TransMontaigne's outstanding letters of credit were approximately $67.1 million and $51.0 million, respectively.

        In connection with the July 1, 2014 sale to NGL, and immediately prior thereto, the TransMontaigne credit facility was terminated.

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(6) INCOME TAXES

        The difference between the income tax benefit reported in the accompanying combined statements of operations and the federal statutory tax rate of 35% relates primarily to the impact of state income taxes, valuation allowance against deferred tax assets, and to the fact that TLP is treated as a partnership for U.S. federal income tax purposes. Because of this, no provision for U.S. federal income taxes has been reflected in the accompanying combined financial statements related to TLP. As a partnership, all income, gains, losses, expenses, deductions and tax credits generated by TLP flow through to the unitholders of the partnership. Income tax expense recorded relates to current state taxes due from tax returns filed on a legal entity basis.

(7) FAIR VALUE MEASUREMENTS

        Generally accepted accounting principles define fair value, establish a framework for measuring fair value and require disclosures about fair value measurements. Generally accepted accounting principles also establish a fair value hierarchy that maximizes the use of relevant observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels. The three levels of the fair value hierarchy are:

        Level 1—Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities and listed derivatives.

        Level 2—Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

        Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management's best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

        The Company's inventory related assets and liabilities, its over-the-counter commodity purchase and sale derivative contracts and its variation margin payables are classified as Level 2 of the fair value hierarchy. The Company estimates fair values based on exchange quoted commodity prices, adjusted as appropriate for contract terms (including maturity) and differences in local markets. These differences are generally valued using inputs from broker or dealer quotations, published indices and consumer pricing services. The determination of the fair values for the derivative contracts and variation margin payables also factor the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit, and priority interests), and also the impact of the Company's nonperformance risk on its liabilities. The Company is able to classify these fair value balances based on the observability of inputs.

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(7) FAIR VALUE MEASUREMENTS (Continued)

        The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 and December 31, 2013.

 
  June 30, 2014  
 
  Level 1   Level 2   Level 3   Total  

Assets carried at fair value (in thousands):

                         

Inventories in pipelines and terminals

  $   $ 542,187   $   $ 542,187  

Inventories in transit via truck and rail

        44,844         44,844  

Derivative contracts

        6,375         6,375  

Liabilities carried at fair value (in thousands):

                         

Inventories due under exchange agreements

        5,788         5,788  

Derivative contracts

        7,765         7,765  

Variation margin payables

        16,888         16,888  

 

 
  December 31, 2013  
 
  Level 1   Level 2   Level 3   Total  

Assets carried at fair value (in thousands):

                         

Inventories in pipelines and terminals

  $   $ 629,567   $   $ 629,567  

Inventories in transit via truck and rail

        53,216         53,216  

Derivative contracts

        47,372         47,372  

Liabilities carried at fair value (in thousands):

                         

Inventories due under exchange agreements

        31,280         31,280  

Derivative contracts

        30,066         30,066  

Variation margin payables

        35,528         35,528  

        The Company also has financial instruments that are not accounted for at fair value, which generally accepted accounting principles require we disclose the fair value. The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that constitute financial instruments and were not accounted for at fair value as of June 30, 2014 and December 31, 2013. We believe the carrying amounts of these financial instruments reasonably approximate their fair

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(7) FAIR VALUE MEASUREMENTS (Continued)

values due to their short-term nature, and in the case of our bank debt due to the borrowings bearing interest at current market interest rates.

 
  June 30, 2014  
 
  Level 1   Level 2   Level 3   Total  

Assets for which the carrying value approximates fair value (in thousands):

                         

Cash and cash equivalents

  $ 71,549   $   $   $ 71,549  

Rack sales accounts receivable, net

        198,702         198,702  

Pipeline sales accounts receivable

        202,795         202,795  

Other pipeline accrued receivables

        3,803         3,803  

Other current assets-restricted cash

    28,526             28,526  

Liabilities for which the carrying value approximates fair value (in thousands):

                         

Accounts payable

        120,656         120,656  

Product purchases accounts payable

        229,363         229,363  

Excise taxes payable

        28,324         28,324  

Other pipeline accrued payables

        12,813         12,813  

Bank debt

        234,000         234,000  

 

 
  December 31, 2013  
 
  Level 1   Level 2   Level 3   Total  

Assets for which the carrying value approximates fair value (in thousands):

                         

Cash and cash equivalents

  $ 74,762   $   $   $ 74,762  

Rack sales accounts receivable, net

        243,520         243,520  

Pipeline sales accounts receivable

        684,881         684,881  

Other pipeline accrued receivables

        6,123         6,123  

Other current assets-restricted cash

    1,000             1,000  

Liabilities for which the carrying value approximates fair value (in thousands):

                         

Accounts payable

        64,351         64,351  

Product purchases accounts payable

        785,112         785,112  

Excise taxes payable

        39,648         39,648  

Other pipeline accrued payables

        20,589         20,589  

Bank debt

        212,000         212,000  

        Accounts receivable are reported net of an allowance for doubtful accounts. As of June 30, 2014 and December 31, 2013, the allowances for doubtful accounts were $3.4 million and $3.8 million, respectively.

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(8) SUBSEQUENT EVENTS

        We have evaluated subsequent events through November 5, 2014, which is the date the financial statements were available to be issued, except for Note 9, as to which we have evaluated subsequent events through December 24, 2014.

        On July 1, 2014, Morgan Stanley consummated the sale of its indirect 100% ownership interest in TransMontaigne Inc. to NGL. TransMontaigne Inc. is the indirect parent and sole member of TransMontaigne GP L.L.C., which is the sole general partner of TLP, a publicly traded master limited partnership. The sale also included Morgan Stanley's limited partnership interests in TLP, the assignment from an affiliate of Morgan Stanley to NGL of certain terminaling services agreements with TLP, and the transfer of certain inventory owned by Morgan Stanley.

        In connection with the July 1, 2014 sale to NGL, and immediately prior thereto, the TransMontaigne credit facility was terminated.

(9) Condensed Consolidating Guarantor and Non-Guarantor Financial Information

        Subsequent to the July 2014 acquisition of the Company by NGL, TransMontaigne Inc. and certain of its subsidiaries became guarantors of certain of NGL's notes, and the other assets and operations acquired from Morgan Stanley were placed into a subsidiary of NGL that also guarantee these notes. As a result, this activity is presented in the guarantor column in the condensed consolidating tables below. TLP and its subsidiaries are not guarantors of these notes. Pursuant to Rule 3-10 of Regulation S-X, certain historical financial data of the Company is shown below, with the operations of TLP shown separately from the other assets and operations of the Company. Under TLP's credit agreement, TLP may make distributions of cash to the extent of its "available cash" as defined in TLP's partnership agreement. There are no significant restrictions upon the ability of the parent or any of the guarantor subsidiaries to obtain funds from their other respective subsidiaries by dividend or loan. NGL is the parent entity of the guarantors of NGL's notes, and NGL is not part of these combined financial statements; as a result, no parent entity activity is shown in the condensed consolidating tables below.

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(9) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining balance sheet at June 30, 2014

 
  Guarantor
Entities
  Non-Guarantor
Entities
  Combining
Adjustments
  Combined  
 
  (in thousands)
 

ASSETS

                         

Current assets:

                         

Cash and cash equivalents

  $ 70,080   $ 1,469   $   $ 71,549  

Rack sales accounts receivable, net

    189,673     9,029         198,702  

Pipeline sales accounts receivable

    202,795             202,795  

Inventories in pipelines and terminals

    542,187             542,187  

Inventories in transit via truck and rail          

    44,844             44,844  

Derivative contracts

    6,375             6,375  

Other pipeline accrued receivables

    3,803             3,803  

Intercompany receivables

        3,058     (3,058 )    

Other

    37,769     3,249     (2,467 )   38,551  
                   

    1,097,526     16,805     (5,525 )   1,108,806  

Property, plant and equipment, net

    37,167     394,319         431,486  

Investment in non-guarantor entities

    48,260         (48,260 )    

Investment in unconsolidated affiliates

        234,002         234,002  

Other assets

    5,157     13,167     (1,648 )   16,676  
                   

  $ 1,188,110   $ 658,293   $ (55,433 ) $ 1,790,970  
                   
                   

LIABILITIES AND EQUITY

                         

Current liabilities:

                         

Accounts payable

  $ 115,788   $ 4,868   $   $ 120,656  

Product purchases accounts payable

    229,363             229,363  

Excise taxes payable

    28,324             28,324  

Inventories due under exchange agreements

    5,788             5,788  

Derivative contracts

    7,765             7,765  

Accrued environmental obligations

    4,208             4,208  

Variation margin payables

    16,888             16,888  

Other pipeline accrued payables

    12,813             12,813  

Intercompany payables

    3,058         (3,058 )    

Other accrued liabilities

    28,385     10,788     (3,853 )   35,320  
                   

    452,380     15,656     (6,911 )   461,125  

Bank debt

        234,000         234,000  

Other

        4,753     (262 )   4,491  
                   

Total liabilities

    452,380     254,409     (7,173 )   699,616  
                   

Equity:

                         

Equity attributable to noncontrolling interests

        355,624         355,624  

Equity attributable to parent

    735,730     48,260     (48,260 )   735,730  
                   

    735,730     403,884     (48,260 )   1,091,354  
                   

  $ 1,188,110   $ 658,293   $ (55,433 ) $ 1,790,970  
                   
                   

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(9) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining balance sheet at December 31, 2013

 
  Guarantor
Entities
  Non-Guarantor
Entities
  Combining
Adjustments
  Combined  
 
  (in thousands)
 

ASSETS

                         

Current assets:

                         

Cash and cash equivalents

  $ 71,499   $ 3,263   $   $ 74,762  

Rack sales accounts receivable, net

    238,924     6,612     (2,016 )   243,520  

Pipeline sales accounts receivable

    684,881             684,881  

Inventories in pipelines and terminals

    629,567             629,567  

Inventories in transit via truck and rail          

    53,216             53,216  

Derivative contracts

    47,372             47,372  

Other pipeline accrued receivables

    6,123             6,123  

Intercompany receivables

        2,072     (2,072 )    

Other

    24,596     3,478     (10,526 )   17,548  
                   

    1,756,178     15,425     (14,614 )   1,756,989  

Property, plant and equipment, net

    38,450     407,045         445,495  

Investment in non-guarantor entities

    49,049         (49,049 )    

Investment in unconsolidated affiliates

        211,605         211,605  

Other assets

    6,146     14,357     (2,146 )   18,357  
                   

  $ 1,849,823   $ 648,432   $ (65,809 ) $ 2,432,446  
                   
                   

LIABILITIES AND EQUITY

                         

Current liabilities:

                         

Accounts payable

  $ 58,634   $ 5,717   $   $ 64,351  

Product purchases accounts payable

    785,112             785,112  

Excise taxes payable

    39,648             39,648  

Inventories due under exchange agreements

    31,280             31,280  

Derivative contracts

    30,066             30,066  

Accrued environmental obligations

    4,303             4,303  

Variation margin payables

    35,528             35,528  

Other pipeline accrued payables

    20,589             20,589  

Intercompany payables

    2,072         (2,072 )    

Other accrued liabilities

    21,543     16,189     (14,469 )   23,263  
                   

    1,028,775     21,906     (16,541 )   1,034,140  

Bank debt

        212,000         212,000  

Other

    3,522     6,059     (219 )   9,362  
                   

Total liabilities

    1,032,297     239,965     (16,760 )   1,255,502  
                   

Equity:

                         

Equity attributable to noncontrolling interests

        359,418         359,418  

Equity attributable to parent

    817,526     49,049     (49,049 )   817,526  
                   

    817,526     408,467     (49,049 )   1,176,944  
                   

  $ 1,849,823   $ 648,432   $ (65,809 ) $ 2,432,446  
                   
                   

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Table of Contents


Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(9) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining statement of operations for the six months ended June 30, 2014

 
  Guarantor
Entities
  Non-Guarantor
Entities
  Combining
Adjustments
  Combined  
 
  (in thousands)
 

Marketing and distribution:

                         

Revenues

  $ 4,000,573   $   $   $ 4,000,573  

Cost of product sold and other direct costs and expenses

    (3,979,083 )       30,255     (3,948,828 )
                   

Net operating margins, exclusive of depreciation and amortization shown separately below

    21,490         30,255     51,745  
                   

Terminals and pipelines:

                         

Revenues

    2,719     77,412     (46,481 )   33,650  

Direct costs and expenses

    (1,271 )   (31,788 )   16,226     (16,833 )
                   

Net operating margins, exclusive of depreciation and amortization shown separately below

    1,448     45,624     (30,255 )   16,817  
                   

Total net operating margins

    22,938     45,624         68,562  
                   

Costs and expenses:

                         

Selling, general, and administrative          

    (31,645 )   (9,521 )       (41,166 )

Depreciation and amortization

    (2,550 )   (14,796 )       (17,346 )

Gain on disposition of assets, net

    98             98  

Earnings from unconsolidated affiliates

        1,438         1,438  
                   

Total costs and expenses

    (34,097 )   (22,879 )       (56,976 )
                   

Operating income (loss)

    (11,159 )   22,745         11,586  
                   

Other income (expenses):

                         

Equity in earnings of non-guarantor entities

    6,401         (6,401 )    

Interest expense

    (1,085 )   (2,667 )       (3,752 )
                   

Total other income (expenses)

    5,316     (2,667 )   (6,401 )   (3,752 )
                   

Earnings (loss) before income taxes          

    (5,843 )   20,078     (6,401 )   7,834  

Income tax expense

    (302 )           (302 )
                   

Net income (loss)

    (6,145 )   20,078     (6,401 )   7,532  

Noncontrolling interests share in earnings of TransMontaigne Partners

        (13,677 )       (13,677 )
                   

Net income (loss) atributable to parent

  $ (6,145 ) $ 6,401   $ (6,401 ) $ (6,145 )
                   
                   

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(9) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining statements of operations and comprehensive income (loss) for the six months ended June 30, 2013

 
  Guarantor
Entities
  Non-Guarantor
Entities
  Combining
Adjustments
  Combined  
 
  (in thousands)
 

Marketing and distribution:

                         

Revenues

  $ 4,678,070   $   $   $ 4,678,070  

Cost of product sold and other direct costs and expenses

    (4,681,232 )       32,445     (4,648,787 )
                   

Net operating margins (loss), exclusive of depreciation and amortization shown separately below

    (3,162 )       32,445     29,283  
                   

Terminals and pipelines:

                         

Revenues

    3,111     80,296     (51,870 )   31,537  

Direct costs and expenses

    (478 )   (34,022 )   19,425     (15,075 )
                   

Net operating margins, exclusive of depreciation and amortization shown separately below

    2,633     46,274     (32,445 )   16,462  
                   

Total net operating margins (loss)          

    (529 )   46,274         45,745  
                   

Costs and expenses:

                         

Selling, general, and administrative

    (22,310 )   (9,750 )       (32,060 )

Depreciation and amortization

    (2,219 )   (14,799 )       (17,018 )

Loss on disposition of assets, net

    (845 )           (845 )

Earnings from unconsolidated affiliates

        36         36  
                   

Total costs and expenses

    (25,374 )   (24,513 )       (49,887 )
                   

Operating income (loss)

    (25,903 )   21,761         (4,142 )
                   

Other income (expenses):

                         

Equity in earnings of non-guarantor entities

    6,007         (6,007 )    

Interest expense

    (1,321 )   (1,991 )       (3,312 )

Foreign currency transaction loss

        (8 )       (8 )
                   

Total other income (expenses)

    4,686     (1,999 )   (6,007 )   (3,320 )
                   

Earnings (loss) before income taxes

    (21,217 )   19,762     (6,007 )   (7,462 )

Income tax (expense) benefit

    (104 )   2         (102 )
                   

Net income (loss)

    (21,321 )   19,764     (6,007 )   (7,564 )

Noncontrolling interests share in earnings of TransMontaigne Partners

        (13,759 )       (13,759 )
                   

Net income (loss) attributable to parent

    (21,321 )   6,005     (6,007 )   (21,323 )

Other comprehensive income—foreign currency translation adjustments attributable to noncontrolling interests

        2         2  
                   

Comprehensive income (loss)

  $ (21,321 ) $ 6,007   $ (6,007 ) $ (21,321 )
                   
                   

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(9) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining statements of cash flows for the six months ended June 30, 2014

 
  Guarantor
Entities
  Non-Guarantor
Entities
  Combined  
 
  (in thousands)
 

Net cash provided by operating activities

  $ 67,200   $ 26,990   $ 94,190  

Cash flows from investing activities:

   
 
   
 
   
 
 

Investments in unconsolidated affiliates

        (23,397 )   (23,397 )

Capital expenditures

    (1,143 )   (2,612 )   (3,755 )

Proceeds from sale of assets

    1         1  
               

Net cash used in investing activities

    (1,142 )   (26,009 )   (27,151 )
               

Cash flows from financing activities:

                   

Borrowings of bank debt

        56,000     56,000  

Repayments of bank debt

        (34,000 )   (34,000 )

Net capital distributed to affiliated entities

    (67,477 )   (7,190 )   (74,667 )

Distributions paid to noncontrolling TransMontaigne Partners' common units

        (17,408 )   (17,408 )

Purchase of common units by TransMontaigne Partners' long-term incentive plan

        (177 )   (177 )
               

Net cash used in financing activities

    (67,477 )   (2,775 )   (70,252 )
               

Decrease in cash and cash equivalents

    (1,419 )   (1,794 )   (3,213 )
               

Cash and cash equivalents at beginning of period

    71,499     3,263     74,762  
               

Cash and cash equivalents at end of period

  $ 70,080   $ 1,469   $ 71,549  
               
               

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(9) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining statements of cash flows for the six months ended June 30, 2013

 
  Guarantor
Entities
  Non-Guarantor
Entities
  Combined  
 
  (in thousands)
 

Net cash provided by (used in) operating activities

  $ (131,253 ) $ 32,482   $ (98,771 )

Cash flows from investing activities:

   
 
   
 
   
 
 

Investments in unconsolidated affiliates

        (70,956 )   (70,956 )

Capital expenditures

    (2,536 )   (10,376 )   (12,912 )

Proceeds from sale of assets

    89         89  
               

Net cash used in investing activities

    (2,447 )   (81,332 )   (83,779 )
               

Cash flows from financing activities:

                   

Borrowings of bank debt

        119,500     119,500  

Repayments of bank debt

        (49,500 )   (49,500 )

Net capital contributed by (distributed to) affiliated entities

    191,244     (6,185 )   185,059  

Distributions paid to noncontrolling TransMontaigne Partners' common units

        (15,016 )   (15,016 )

Purchase of common units by TransMontaigne Partners' long-term incentive plan

        (166 )   (166 )

Other

        (398 )   (398 )
               

Net cash provided by financing activities

    191,244     48,235     239,479  
               

Increase (decrease) in cash and cash equivalents

    57,544     (615 )   56,929  

Foreign currency translation effect on cash

        46     46  
               

Cash and cash equivalents at beginning of period

    8,411     6,745     15,156  
               

Cash and cash equivalents at end of period

  $ 65,955   $ 6,176   $ 72,131  
               
               

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LETTER OF TRANSMITTAL

to Tender
Outstanding Unregistered 6.875% Senior Notes due 2021
of
NGL ENERGY PARTNERS LP
NGL ENERGY FINANCE CORP.
Pursuant to the Exchange Offer and Prospectus dated January 13, 2015

THE EXCHANGE OFFER AND WITHDRAWAL RIGHTS WILL EXPIRE AT 12:00 MIDNIGHT, NEW YORK CITY TIME, AT THE END OF FEBRUARY 10, 2015 (THE "EXPIRATION DATE"), UNLESS THE EXCHANGE OFFER IS EXTENDED BY THE ISSUERS (AS DEFINED BELOW).

The Exchange Agent for the Exchange Offer is:
U.S. Bank National Association

By Registered or Certified Mail, Overnight Delivery or Hand Delivery:

U.S. Bank National Association
Corporate Trust Services
Attn: Specialized Finance Department
111 Fillmore Ave. E
St. Paul, Minnesota 55107

FACSIMILE TRANSMISSION: (651) 466-7367

CONFIRM BY TELEPHONE: (800) 934-6802

        If you wish to exchange currently outstanding unregistered 6.875% Senior Notes due 2021 ("old notes") for an equal aggregate principal amount at maturity of registered 6.875% Senior Notes due 2021 ("new notes") pursuant to the exchange offer, you must validly tender (and not withdraw) old notes to the Exchange Agent prior to the Expiration Date.

        The undersigned hereby acknowledges receipt of the prospectus, dated January 13, 2015 (the "Prospectus"), of NGL Energy Partners LP and NGL Energy Finance Corp. (collectively, the "Issuers"), and this letter of transmittal (the "Letter of Transmittal"), which together describe the Issuers' offer (the "Exchange Offer") to exchange the old notes for a like principal amount of the new notes that have been registered under the Securities Act of 1933, as amended (the "Securities Act"). Capitalized terms used but not defined herein have the respective meanings given to them in the Prospectus.

        The Issuers reserve the right, at any time or from time to time, to extend the Exchange Offer at their discretion, in which event the term "Expiration Date" shall mean the latest date to which the Exchange Offer is extended. The Issuers shall notify the Exchange Agent and each registered holder of the old notes of any extension by oral or written notice prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.

        This Letter of Transmittal is to be used by holders of the old notes. Tender of old notes is to be made according to the Automated Tender Offer Program ("ATOP"), of the Depository Trust Company ("DTC"), pursuant to the procedures set forth in the Prospectus under the caption "Exchange Offer—Procedures for Tendering." DTC participants that are accepting the Exchange Offer must transmit their acceptance to DTC, which will verify the acceptance and execute a book-entry delivery to the Exchange Agent's DTC account. DTC will then send a computer-generated message known as an "agent's

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message" to the Exchange Agent for its acceptance. For you to validly tender your old notes in the Exchange Offer, the Exchange Agent must receive, prior to the Expiration Date, an agent's message under the ATOP procedures that confirms that:

        BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGEMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.


PLEASE READ THE ACCOMPANYING INSTRUCTIONS CAREFULLY.

Ladies and Gentlemen:

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        You may, if you are unable to make all of the representations and warranties contained in Item 5 above and as otherwise permitted in the Registration Rights Agreement (as defined below), elect to have your old notes registered in the shelf registration statement described in the registration rights agreement, dated as of October 16, 2013 (the "Registration Rights Agreement"), by and among the Issuers, the initial guarantors party thereto and RBC Capital Markets, LLC, as representative of the Initial Purchasers (as defined therein). Such election may be made by notifying the Issuers in writing at, Attention: Atanas H. Atanasov. By making such election, you agree, as a holder of old notes participating in a shelf registration, to indemnify and hold harmless the Issuers, the guarantors, and their respective directors, each of the officers of the Issuers and the guarantors who signs such shelf registration statement, and each person who controls the Issuers or any of the guarantors, within the meaning of either the Securities Act or the Securities Exchange Act of 1934, as amended, and the respective officers, directors, partners, employees, representatives and agents of each such person, from and against any and all losses, claims, damages or liabilities caused by any untrue statement or alleged untrue statement of a material fact contained in any shelf registration statement or prospectus, or in any supplement thereto or amendment thereof, or caused by the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; but only with respect to information relating to the undersigned furnished in writing by or on behalf of the undersigned expressly for use in a shelf registration statement, a prospectus or any amendments or supplements thereto. Any such indemnification shall be governed by the terms and subject to the conditions set forth in the Registration Rights Agreement, including, without limitation, the provisions regarding notice, retention of counsel, contribution and payment of expenses set forth therein. The above summary of the indemnification provisions of the Registration Rights Agreement is not intended to be exhaustive and is qualified in its entirety by the Registration Rights Agreement.

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INSTRUCTIONS
FORMING PART OF THE TERMS AND CONDITIONS OF THE EXCHANGE OFFER

        Any confirmation of a book-entry transfer to the Exchange Agent's account at DTC of old notes tendered by book-entry transfer (a "Book-Entry Confirmation"), as well as an agent's message and any other documents required by this Letter of Transmittal, must be received by the Exchange Agent at its address set forth herein prior to 12:00 midnight, New York City time, at the end of the Expiration Date.

        Tenders of old notes will be accepted only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. The entire principal amount of old notes delivered to the Exchange Agent will be deemed to have been tendered unless otherwise communicated to the Exchange Agent. If the entire principal amount of all old notes is not tendered, then old notes for the principal amount of old notes not tendered and new notes issued in exchange for any old notes accepted will be delivered to the holder via the facilities of DTC promptly after the old notes are accepted for exchange.

        All questions as to the validity, form, eligibility (including time of receipt), acceptance and withdrawal of tendered old notes will be determined by the Issuers, in their sole discretion, which determination will be final and binding. The Issuers reserve the absolute right to reject any or all tenders not in proper form or the acceptance for exchange of which may, in the opinion of counsel for the Issuers, be unlawful. The Issuers also reserve the absolute right to waive any of the conditions of the Exchange Offer or any defect or irregularity in the tender of any old notes. The Issuers' interpretation of the terms and conditions of the Exchange Offer (including the instructions on this Letter of Transmittal) will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within such time as the Issuers shall determine. Although the Issuers intend to notify holders of defects or irregularities with respect to tenders of old notes, neither the Issuers, the Exchange Agent nor any other person shall be under any duty to give notification of any defects or irregularities in tenders or incur any liability for failure to give such notification. Tenders of old notes will not be deemed to have been made until such defects or irregularities have been cured or waived. Any old notes received by the Exchange Agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned by the Exchange Agent to the tendering holders, unless otherwise provided in this Letter of Transmittal, as soon as practicable following the Expiration Date.

        Requests for assistance or for additional copies of the Prospectus or this Letter of Transmittal may be directed to the Exchange Agent at the address or telephone number set forth on the cover page of this Letter of Transmittal. Holders may also contact their broker, dealer, commercial bank, trust company or other nominee for assistance concerning the Exchange Offer.

        Tenders may be withdrawn only pursuant to the limited withdrawal rights set forth in the Prospectus under the caption "Exchange Offer—Withdrawal of Tenders."

        There is no procedure for guarantee of late delivery in the Exchange Offer.


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LOGO

        Until July 12, 2015, all dealers that effect transactions in these securities, whether or not participating in the offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to unsold allotments or subscriptions.