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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 wa