Edgar Filing: NGL Energy Partners LP

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2013

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-35172

NGL Energy Partners LP

(Exact Name of Registrant as Specified in Its Charter)

Delaware		27-3427920
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

6120 South Yale Avenue Suite 805 Tulsa, Oklahoma		74136
(Address of Principal Executive Offices)		(Zip code)

(918) 481-1119

(Registrant’s Telephone Number, Including Area Code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o		Accelerated filer x

Non-accelerated filer o		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

As of August 5, 2013, there were 62,315,851 common units and 5,919,346 subordinated units issued and outstanding.

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PART I

Item 1.	Financial Statements (Unaudited)	3

	Condensed Consolidated Balance Sheets as of June 30, 2013 and March 31, 2013	3
	Condensed Consolidated Statements of Operations for the three months ended June 30, 2013 and 2012	4
	Condensed Consolidated Statements of Comprehensive Loss for the three months ended June 30, 2013 and 2012	5
	Condensed Consolidated Statement of Changes in Partners’ Equity for the three months ended June 30, 2013	6
	Condensed Consolidated Statements of Cash Flows for the three months ended June 30, 2013 and 2012	7
	Notes to Condensed Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	53

PART II

Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 3.	Defaults Upon Senior Securities	54
Item 4.	Mine Safety Disclosures	54
Item 5.	Other Information	54
Item 6.	Exhibits	55

Signatures		56

Exhibit Index		57

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Forward-Looking Statements

This Quarterly Report on Form 10-Q 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 quarterly report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “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. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:

· the prices and market demand for crude oil and natural gas liquids;

· energy prices generally;

· the price of propane compared to the price of alternative and competing fuels;

· the general level of crude oil, natural gas, and natural gas liquids production;

· the general level of demand for crude oil and natural gas liquids;

· the availability of supply of crude oil and natural gas liquids;

· the level of crude oil and natural gas production in producing basins in which we have water treatment facilities;

· the ability to obtain adequate supplies of propane and distillates for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane to market areas;

· actions taken by foreign oil and gas producing nations;

· the political and economic stability of petroleum producing nations;

· the effect of weather conditions on demand for oil, natural gas and natural gas liquids;

· the effect of natural disasters or other significant weather events;

· availability of local, intrastate and interstate transportation infrastructure, including with respect to our truck, rail, and barge transportation services;

· availability and marketing of competitive fuels;

· the impact of energy conservation efforts;

· energy efficiencies and technological trends;

· governmental regulation and taxation;

· the impact of legislative and regulatory actions on hydraulic fracturing;

· hazards or operating risks incidental to the transporting and distributing of petroleum products that may not be fully covered by insurance;

· the maturity of the propane industry and competition from other propane distributors;

· loss of key personnel;

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· the ability to renew contracts with key customers;

· the fees we charge and the margins we realize for our terminal services;

· the ability to renew leases for general purpose and high pressure rail cars;

· the ability to renew leases for underground natural gas liquids storage;

· the nonpayment or nonperformance by our customers;

· the availability and cost of capital and our ability to access certain capital sources;

· a deterioration of the credit and capital markets;

· the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results;

· the ability to successfully integrate acquired assets and businesses;

· changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations and the impact of such laws and regulations (now existing or in the future) on our business operations, including our sales of crude oil, condensate, and natural gas liquids, our processing of wastewater, and transportation and hedging activities; and

· the costs and effects of legal and administrative proceedings.

You should not put undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date of this quarterly report. Except as required by state and federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events, or otherwise. When considering forward-looking statements, please review the risks described under “Item 1A — Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended March 31, 2013.

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PART I

Item 1. Financial Statements (Unaudited)

NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Balance Sheets

As of June 30, 2013 and March 31, 2013

(U.S. Dollars in Thousands, except unit amounts)

	June 30,			March 31,
	2013			2013

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,603		$	11,561
Accounts receivable - trade, net of allowance for doubtful accounts of $1,743 and $1,760, respectively	545,317			562,889
Accounts receivable - affiliates	14,479			22,883
Inventories	208,329			126,895
Prepaid expenses and other current assets	39,805			37,891
Total current assets	812,533			762,119

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $62,910 and $50,127, respectively	536,451			516,937
GOODWILL	563,186			563,146
INTANGIBLE ASSETS, net of accumulated amortization of $55,453 and $44,155, respectively	434,861			442,603
OTHER NONCURRENT ASSETS	6,270			6,542
Total assets	$	2,353,301		$	2,291,347

LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES:
Trade accounts payable	$	571,286		$	535,687
Accrued expenses and other payables	96,458			85,703
Advance payments received from customers	35,252			22,372
Accounts payable - affiliates	10,504			6,900
Current maturities of long-term debt	8,720			8,626
Total current liabilities	722,220			659,288

LONG-TERM DEBT, net of current maturities	781,816			740,436
OTHER NONCURRENT LIABILITIES	3,539			2,205

COMMITMENTS AND CONTINGENCIES

PARTNERS’ EQUITY, per accompanying statement:
General Partner — 0.1% interest; 53,676 notional units outstanding at June 30, 2013 and March 31, 2013	(49,999		)	(50,497		)
Limited Partners — 99.9% interest — Common units — 47,703,313 units outstanding at June 30, 2013 and March 31, 2013	881,611			920,998
Subordinated units — 5,919,346 units outstanding at June 30, 2013 and March 31, 2013	7,615			13,153
Accumulated other comprehensive income (loss) — Foreign currency translation	(1		)	24
Noncontrolling interests	6,500			5,740
Total partners’ equity	845,726			889,418
Total liabilities and partners’ equity	$	2,353,301		$	2,291,347

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Statements of Operations

Three Months Ended June 30, 2013 and 2012

(U.S. Dollars in Thousands, except unit and per unit amounts)

	Three Months			Three Months
	Ended			Ended
	June 30,			June 30,
	2013			2012
REVENUES:
Crude oil logistics	$	930,794		$	73,517
Water services	20,513			1,941
Natural gas liquids logistics	360,959			191,617
Retail propane	72,217			59,208
Other	1,474			153
Total Revenues	1,385,957			326,436

COST OF SALES:
Crude oil logistics	909,219			76,883
Water services	583			616
Natural gas liquids logistics	350,251			184,045
Retail propane	43,023			37,441
Total Cost of Sales	1,303,076			298,985

OPERATING COSTS AND EXPENSES:
Operating	49,045			23,338
General and administrative	18,454			9,960
Depreciation and amortization	22,724			9,227
Operating Loss	(7,342		)	(15,074		)

OTHER INCOME (EXPENSE):
Interest expense	(10,622		)	(3,800		)
Loss on early extinguishment of debt	—			(5,769		)
Interest income	398			366
Other, net	(348		)	26
Loss Before Income Taxes	(17,914		)	(24,251		)

INCOME TAX PROVISION (BENEFIT)	406			(459		)

Net Loss	(17,508		)	(24,710		)

Net Income Allocated to General Partner	(1,688		)	(95		)

Net (Income) Loss Attributable to Noncontrolling Interests	(125		)	60

Net Loss Attributable to Parent Equity Allocated to Limited Partners	$	(19,321	)	$	(24,745	)

Basic and Diluted Loss Per Common Unit	$	(0.35	)	$	(0.76	)

Basic and Diluted Loss per Subordinated Unit	$	(0.46	)	$	(0.77	)

Basic and Diluted Weighted Average Units Outstanding:
Common	47,703,313			26,529,133
Subordinated	5,919,346			5,919,346

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Statements of Comprehensive Loss

Three Months Ended June 30, 2013 and 2012

(U.S. Dollars in Thousands)

	Three Months			Three Months
	Ended			Ended
	June 30,			June 30,
	2013			2012

Net loss	$	(17,508	)	$	(24,710	)
Other comprehensive loss, net of tax:
Change in foreign currency translation adjustment	(25		)	(13		)
Comprehensive loss	$	(17,533	)	$	(24,723	)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Statement of Changes in Partners’ Equity

Three Months Ended June 30, 2013

(U.S. Dollars in Thousands, except unit amounts)

												Accumulated
												Other
				Limited Partners								Comprehensive						Total
	General			Common				Subordinated				Income			Noncontrolling			Partners’
	Partner			Units	Amount			Units	Amount			(Loss)			Interests			Equity
BALANCES, MARCH 31, 2013	$	(50,497	)	47,703,313	$	920,998		5,919,346	$	13,153		$	24		$	5,740		$	889,418
Distributions to partners	(1,190		)	—	(22,778		)	—	(2,826		)	—			(365		)	(27,159		)
Contributions	—			—	—			—	—			—			1,000			1,000
Net income (loss)	1,688			—	(16,609		)	—	(2,712		)	—			125			(17,508		)
Foreign currency translation adjustment	—			—	—			—	—			(25		)	—			(25		)
BALANCES, June 30, 2013	$	(49,999	)	47,703,313	$	881,611		5,919,346	$	7,615		$	(1	)	$	6,500		$	845,726

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Statements of Cash Flows

Three Months Ended June 30, 2013 and 2012

(U.S. Dollars in Thousands)

	Three Months			Three Months
	Ended			Ended
	June 30,			June 30,
	2013			2012
OPERATING ACTIVITIES:
Net loss	$	(17,508	)	$	(24,710	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization, including debt issuance cost amortization	24,746			9,928
Loss on early extinguishment of debt	—			5,769
Non-cash equity-based compensation expense	7,075			655
Loss on sale of assets	373			7
Provision for doubtful accounts	364			293
Commodity derivative (gain) loss	7,209			(4,228		)
Other	187			62
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable - trade	17,633			139,458
Accounts receivable - affiliates	8,404			5,407
Inventories	(81,124		)	(49,519		)
Prepaid expenses and other assets	218			(929		)
Trade accounts payable	35,599			(140,417		)
Accrued expenses and other payables	6,276			(8,851		)
Accounts payable - affiliates	3,604			(2,724		)
Advance payments received from customers	12,880			14,890
Net cash provided by (used in) operating activities	25,936			(54,909		)

INVESTING ACTIVITIES:
Purchases of long-lived assets	(30,192		)	(2,684		)
Acquisitions of businesses, including acquired working capital	(5,362		)	(295,341		)
Cash flows from commodity derivatives	(11,054		)	15,514
Proceeds from sales of assets	1,088			361
Other	—			212
Net cash used in investing activities	(45,520		)	(281,938		)

FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	255,000			462,175
Payments on revolving credit facilities	(212,000		)	(333,675		)
Issuance of senior notes	—			250,000
Proceeds from borrowings on other long-term debt	880			—
Payments on other long-term debt	(2,884		)	(300		)
Debt issuance costs	(2,211		)	(18,450		)
Contributions	1,000			580
Distributions	(27,159		)	(9,175		)
Proceeds from sale of common units, net of offering costs	—			(673		)
Net cash provided by financing activities	12,626			350,482
Net increase (decrease) in cash and cash equivalents	(6,958		)	13,635
Cash and cash equivalents, beginning of period	11,561			7,832
Cash and cash equivalents, end of period	$	4,603		$	21,467

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

Note 1 - Organization and Operations

NGL Energy Partners LP (“we”, “our”, or the “Partnership”) is a Delaware limited partnership formed in September 2010. NGL Energy Holdings LLC serves as our general partner. At the time of formation, our operations included a wholesale natural gas liquids business and a retail propane business. We completed an initial public offering in May 2011. Subsequent to our initial public offering, we significantly expanded our operations through a number of business combinations, including the following:

· On October 3, 2011, we completed a business combination with E. Osterman Propane, Inc., its affiliated companies, and members of the Osterman family, whereby we acquired retail propane operations in the northeastern United States.

· On November 1, 2011, we completed a business combination with SemStream, L.P. (“SemStream”), whereby we acquired SemStream’s wholesale natural gas liquids supply and marketing operations and its 12 natural gas liquids terminals.

· On January 3, 2012, we completed a business combination with seven companies associated with Pacer Propane Holding, L.P., whereby we acquired retail propane operations, primarily in the western United States.

· On February 3, 2012, we completed a business combination with North American Propane, Inc., whereby we acquired retail propane and distillate operations in the northeastern United States.

· During the year ended March 31, 2012, we completed three additional separate business combination transactions to acquire retail propane operations.

· On June 19, 2012, we completed a business combination with High Sierra Energy, LP and High Sierra Energy GP, LLC (collectively, “High Sierra”), whereby we acquired all of the ownership interests in High Sierra. High Sierra’s businesses include crude oil gathering, transportation and marketing; water treatment, disposal, and transportation; and natural gas liquids transportation and marketing.

· On November 1, 2012, we completed a business combination whereby we acquired Pecos Gathering & Marketing, L.L.C. and certain of its affiliated companies (collectively, “Pecos”). The business of Pecos consists primarily of crude oil purchasing and logistics operations in Texas and New Mexico.

· On December 31, 2012, we completed a business combination whereby we acquired all of the membership interests in Third Coast Towing, LLC (“Third Coast”). The business of Third Coast consists primarily of transporting crude oil via barge.

· During the year ended March 31, 2013, we completed six additional separate business combination transactions to acquire retail propane and distillate operations, primarily in the northeastern and southeastern United States.

· During the year ended March 31, 2013, we completed four additional separate acquisitions to expand the assets and operations of our crude oil logistics and water services businesses.

· During the three months ended June 30, 2013, we completed two acquisitions of retail propane and distillate businesses.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

As of June 30, 2013, our businesses include:

· A crude oil logistics business, the assets of which include crude oil terminals, pipeline injection stations, a fleet of trucks, a fleet of leased rail cars, and a fleet of barges and tow boats. 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. The operations of our crude oil logistics segment began with our June 2012 merger with High Sierra.

· A water services business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks. Our water services 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. The operations of our water services segment began with our June 2012 merger with High Sierra.

· Our natural gas liquids logistics business, which supplies natural gas liquids to retailers, wholesalers, and refiners throughout the United States and in Canada, and which provides natural gas liquids terminaling services through its 17 terminals throughout the United States and rail car transportation services through its fleet of owned and predominantly leased rail cars. Our natural gas liquids logistics segment purchases propane, butane, and other natural gas liquids from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets.

· Our retail propane business, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain re-sellers in more than 20 states.

Note 2 — Significant Accounting Policies

Basis of Presentation

The unaudited condensed consolidated financial statements as of and for the three months ended June 30, 2013 and 2012 include our accounts and those of our controlled subsidiaries. All significant intercompany transactions and account balances have been eliminated in consolidation. The unaudited condensed consolidated balance sheet as of March 31, 2013 is derived from audited financial statements.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim consolidated financial information and in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). The unaudited condensed consolidated financial statements include all adjustments that we consider necessary for a fair presentation of the financial position and results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed consolidated financial statements do not include all the information and notes required by GAAP for complete annual consolidated financial statements. However, we believe that the disclosures made are adequate to make the information not misleading. These interim unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements for the fiscal year ended March 31, 2013 included in our Annual Report on Form 10-K. Due to the seasonal nature of our natural gas liquids operations and other factors, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

Significant Accounting Policies

Our significant accounting policies are consistent with those disclosed in Note 2 of our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended March 31, 2013.

Revenue Recognition

We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. We record terminaling, storage and service revenues at the time the service is performed and we record tank and other rentals over the term of the lease. Revenues for the wastewater disposal business are recognized upon receipt of the wastewater at our disposal facilities.

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. Amounts billed to customers for shipping and handling costs are included in revenues in the consolidated statements of operations. Shipping and handling costs associated with product sales are included in operating expenses in the consolidated statements of operations.

We enter into certain contracts whereby we agree to purchase product from a counterparty and to sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into concurrently and are entered into in contemplation of each other, we record the revenues for these transactions net of the cost of sales.

Fair Value Measurements

We apply fair value measurements to certain assets and liabilities, principally our commodity derivative instruments and assets and liabilities acquired in business combinations. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

· Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

· Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity price swap and option contracts and interest rate protection agreements. The majority of our fair value measurements related to our derivative financial instruments were categorized as Level 2 at June 30, 2013 and March 31, 2013 (see Note 11). We determine the fair value of all our derivative financial instruments utilizing pricing models for significantly similar instruments. Inputs to the pricing model include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

· Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any fair value measurements categorized as Level 3 at June 30, 2013 or March 31, 2013.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability.

Supplemental Cash Flow Information

Supplemental cash flow information is as follows for the periods indicated:

	Three Months Ended June 30,
	2013		2012
	(in thousands)

Interest paid, exclusive of debt issuance costs	$	8,485	$	3,237
Income taxes paid	$	281	$	176

Value of common units issued in business combinations	$	—	$	431,444

Cash flows from commodity derivative instruments are classified as cash flows from investing activities in the consolidated statements of cash flows.

Inventories

Inventories consist of the following:

	June 30, 2013		March 31, 2013
	(in thousands)
Crude oil	$	43,673	$	46,156
Propane	110,718		45,428
Other natural gas liquids	42,877		24,090
Other	11,061		11,221
	$	208,329	$	126,895

Note 3 — Acquisitions

Fiscal 2013

As described in Note 1, we have completed a number of business combinations since our initial public offering. Pursuant to GAAP, an entity is allowed a reasonable period of time to obtain the information necessary to identify and measure the value of the assets acquired and liabilities assumed in a business combination. We are still within this measurement period for certain of our acquisitions completed during the year ended March 31, 2013, including:

· Pecos, which we acquired in November 2012;

· Third Coast, which we acquired in December 2012;

· Four acquisitions of crude oil logistics and water services businesses completed during the fiscal year ended March 31, 2013; and

· Three acquisitions of retail propane businesses completed during the fiscal year ended March 31, 2013.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

We continue the process of gathering information to ascertain the existence and fair value of assets acquired and liabilities assumed in these acquisitions, and the values we have recorded for the assets acquired and liabilities assumed in these acquisitions is subject to change. The preliminary values we have recorded for the assets acquired and liabilities assumed as of the acquisition dates are summarized below (in thousands):

							Crude Oil and			Retail
							Water Services			Propane
	Pecos			Third Coast			Businesses			Businesses
Accounts receivable - trade	$	73,704		$	2,248		$	2,660		$	464
Inventories	1,903			—			191			476
Other current assets	1,425			140			738			47
Property, plant and equipment:
Land	224			—			—			255
Retail propane equipment	—			—			—			4,853
Vehicles	19,193			—			—			1,620
Water treatment equipment	—			—			13,322			—
Buildings and leasehold improvements	1,248			—			—			670
Barges and tow boats	—			12,883			—			—
Other equipment	1,090			30			5,671			16
Intangible assets:
Customer relationships	8,000			4,000			6,800			3,240
Tradenames	1,000			500			500			324
Non-compete agreements	—			—			510			324
Goodwill	86,661			22,551			43,822			4,348
Other noncurrent assets	—			2,733			—			—
Trade accounts payable	(50,808		)	(2,048		)	—			—
Accrued expenses	(1,019		)	(154		)	(5,400		)	(1,268		)
Long-term debt	(10,234		)	—			(1,340		)	(2,265		)
Other noncurrent liabilities	—			—			(156		)	—
Noncontrolling interests	—			—			(2,333		)	—
Total consideration paid	$	132,387		$	42,883		$	64,985		$	13,104

Consideration paid for these acquisitions consisted of the following (in thousands):

					Crude Oil and		Retail
					Water Services		Propane
	Pecos		Third Coast		Businesses		Businesses
Cash paid, net of cash acquired	$	87,444	$	35,000	$	52,552	$	10,880
Value of common units issued	44,943		7,883		12,433		2,224
Total consideration paid	$	132,387	$	42,883	$	64,985	$	13,104

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

Fiscal 2014

During the three months ended June 30, 2013, we completed two acquisitions of retail propane businesses for a combined purchase price of approximately $5.8 million. We also assumed $0.4 million of long-term debt in the form of non-compete agreements. We are still in the process of gathering information to ascertain the existence and fair value of assets acquired and liabilities assumed in these acquisitions.

Note 4 — Earnings per Unit

Our earnings per common and subordinated unit for the periods indicated below were computed as follows:

	Three Months Ended June 30,
	2013			2012
	(in thousands, except unit and per unit amounts)
Loss attributable to parent equity	$	(17,633	)	$	(24,650	)
Income allocated to general partner(*)	(1,688		)	(95		)
Loss allocated to limited partners	$	(19,321	)	$	(24,745	)

Loss allocated to:
Common unitholders	$	(16,609	)	$	(20,200	)
Subordinated unitholders	$	(2,712	)	$	(4,545	)

Weighted average common units outstanding	47,703,313			26,529,133

Weighted average subordinated units outstanding	5,919,346			5,919,346

Loss per common unit - basic and diluted	$	(0.35	)	$	(0.76	)

Loss per subordinated unit - basic and diluted	$	(0.46	)	$	(0.77	)

(*) The income allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights, which are described in Note 10.

The restricted units described in Note 10 were antidilutive for the three-month periods ended June 30, 2013 and 2012.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

Note 5 — Property, Plant and Equipment

Our property, plant and equipment consists of the following as of the dates indicated:

	June 30,			March 31,
Description and Useful Life	2013			2013
	(in thousands)

Natural gas liquids terminal assets (30 years)	$	64,431		$	63,637
Retail propane equipment (5-20 years)	156,741			152,802
Vehicles (5-10 years)	88,261			85,200
Water treatment facilities and equipment (3-30 years)	100,890			91,601
Crude oil tanks and related equipment (2-30 years)	22,027			21,308
Barges and tow boats (20 years)	21,135			21,135
Information technology equipment (3-5 years)	13,137			12,169
Buildings and leasehold improvements (5-30 years)	50,916			48,394
Land	22,164			21,604
Other (3-10 years)	17,381			17,288
Construction in progress	42,278			31,926
	599,361			567,064
Less: Accumulated depreciation	(62,910		)	(50,127		)
Net property, plant and equipment	$	536,451		$	516,937

Depreciation expense was $13.4 million and $6.1 million for the three months ended June 30, 2013 and 2012, respectively.

Note 6 — Goodwill and Intangible Assets

The changes in the balance of goodwill during the three months ended June 30, 2013 were as follows (in thousands):

Balance at March 31, 2013	$	563,146
Acquisitions	40
Balance at June 30, 2013	$	563,186

Goodwill by reportable segment is as follows:

	June 30,		March 31,
	2013		2013
	(in thousands)
Crude oil logistics	$	244,073	$	244,073
Water services	119,668		119,668
Natural gas liquids logistics	87,136		87,136
Retail propane	112,309		112,269
	$	563,186	$	563,146

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

Our intangible assets consist of the following as of the dates indicated:

		June 30, 2013				March 31, 2013
		Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Useful Lives	Amount		Amortization		Amount		Amortization
		(in thousands)
Amortizable —
Customer relationships*	5-20 years	$	408,975	$	39,387	$	407,835	$	30,959
Lease and other agreements	1-8 years	15,210		7,642		15,210		7,018
Non-compete agreements	2-7 years	12,020		3,644		11,855		2,871
Trade names	3-10 years	2,784		401		2,784		326
Debt issuance costs	5-10 years	21,705		4,379		19,494		2,981
Total amortizable		460,694		55,453		457,178		44,155

Non-amortizable —
Trade names	Indefinite	29,620		—		29,580		—
Total		$	490,314	$	55,453	$	486,758	$	44,155

* The weighted-average remaining amortization period for customer relationship intangible assets is approximately 11 years.

Expected amortization of our amortizable intangible assets is as follows (in thousands):

Year Ending March 31,
2014 (nine months)	$	33,911
2015	43,547
2016	41,777
2017	40,002
2018	34,322
Thereafter	211,682
	$	405,241

Amortization expense was as follows:

	Three Months Ended June 30,
Recorded in	2013		2012
	(in thousands)
Cost of sales	$	625	$	200
Depreciation and amortization	9,276		3,166
Interest expense	1,397		501
Loss on early extinguishment of debt	—		5,769
	$	11,298	$	9,636

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

Note 7 — Long-Term Debt

Our long-term debt consists of the following:

	June 30,		March 31,
	2013		2013
	(in thousands)
Revolving credit facility —
Expansion capital loans	$	444,500	$	441,500
Working capital loans	76,000		36,000

Senior notes	250,000		250,000

Other notes payable	20,036		21,562
	790,536		749,062
Less - current maturities	8,720		8,626
Long-term debt	$	781,816	$	740,436

On June 19, 2012, we entered into a credit agreement (the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). Also on June 19, 2012, we entered into a note purchase agreement (the “Note Purchase Agreement”) whereby we issued $250 million of Senior Notes in a private placement (the “Senior Notes”).

Credit Agreement

The Working Capital Facility had a total capacity of $325.0 million for cash borrowings and letters of credit at June 30, 2013. At June 30, 2013, we had outstanding cash borrowings of $76.0 million and outstanding letters of credit of $73.9 million on the Working Capital Facility, leaving a remaining capacity of $175.1 million at June 30, 2013. The Expansion Capital Facility had a total capacity of $725.0 million for cash borrowings at June 30, 2013. At June 30, 2013, we had outstanding cash borrowings of $444.5 million on the Expansion Capital Facility, leaving a remaining capacity of $280.5 million at June 30, 2013. The capacity available under the Working Capital Facility may be limited by a “borrowing base,” as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time. At June 30, 2013, the borrowing base provisions of the Credit Agreement did not have any impact on the capacity available under the Working Capital Facility.

The commitments under the Credit Agreement expire on June 19, 2017. We have the right to pre-pay outstanding borrowings under the Credit Agreement without incurring any penalties, and pre-payments of principal may be required if we enter into certain transactions to sell assets or obtain new borrowings.

All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 1.75% to 2.75% per annum or (ii) an adjusted LIBOR rate plus a margin of 2.75% to 3.75% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At June 30, 2013, the interest rate in effect on outstanding LIBOR borrowings was 3.2%, calculated as the LIBOR rate of 0.2% plus a margin of 3.0%. At June 30, 2013, the interest rate in effect on outstanding base rate borrowings was 5.25%, calculated as the base rate of 3.25% plus a margin of 2.0%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. At June 30, 2013, our outstanding borrowings and interest rates under our Revolving Credit Facility were as follows (dollars in thousands):

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

	Amount		Rate
Expansion Capital Facility — LIBOR borrowings	$	444,500	3.20	%
Working Capital Facility — LIBOR borrowings	48,500		3.20	%
Base rate borrowings	27,500		5.25	%

The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our “leverage ratio,” as defined in the Credit Agreement, cannot exceed 4.25 to 1.0 at any quarter end. At June 30, 2013, our leverage ratio was approximately 3 to 1. The Credit Agreement also specifies that our “interest coverage ratio,” as defined in the Credit Agreement, cannot be less than 2.75 to 1 as of the last day of any fiscal quarter. At June 30, 2013, our interest coverage ratio was approximately 7 to 1.

The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.

At June 30, 2013, we were in compliance with all covenants under the Credit Agreement.

Senior Notes

The Senior Notes have an aggregate principal amount of $250.0 million and bear interest at a fixed rate of 6.65%. Interest is payable quarterly. The Senior Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to pre-pay outstanding principal, although we would incur a pre-payment penalty. The Senior Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create or permit certain liens, (iv) create or permit restrictions on the ability of certain of our subsidiaries to pay dividends or make other distributions to us, (v) enter into transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate or merge or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains the same leverage ratio and interest coverage ratio requirements as our Credit Agreement, which are described above.

The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary grace and cure periods): (i) non-payment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the Senior Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10 million, (iv) the rendering of a judgment for the payment of money in excess of $10 million, (v) the failure of the Note Purchase Agreement, the Senior Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregate principal amount of the then outstanding Senior Notes of any series may declare all of the Senior Notes of such series to be due and payable immediately.

At June 30, 2013, we were in compliance with all covenants under the Note Purchase Agreement and the Senior Notes.

Previous credit facilities

On June 19, 2012, we made a principal payment of $306.8 million to retire our previous revolving credit facility. Upon retirement of this facility, we wrote off the portion of the debt issuance cost asset that had not yet been amortized. This expense is reported as “Loss on early extinguishment of debt” in our consolidated statement of operations.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

Other Notes Payable

We have executed various non-interest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also acquired certain notes payable in our acquisition of Pecos that relate to equipment financing; the interest rates on these notes payable range from 2.1% to 4.9% at June 30, 2013.

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows as of June 30, 2013 (in thousands):

	Revolving				Other
	Credit		Senior		Notes
Year ending March 31,	Facility		Notes		Payable		Total
2014 (nine months)	$	—	$	—	$	6,302	$	6,302
2015	—		—		6,735		6,735
2016	—		—		3,386		3,386
2017	—		—		2,108		2,108
2018	520,500		25,000		1,252		546,752
Thereafter	—		225,000		253		225,253
	$	520,500	$	250,000	$	20,036	$	790,536

Note 8 — Income Taxes

We believe that we qualify as a partnership for income tax purposes. As such, we generally do not pay U.S. federal income tax. Rather, each owner reports his or her share of our income or loss on his or her individual tax return. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined, as we do not have access to information regarding each partner’s basis in the Partnership.

We have two taxable corporate subsidiaries in the United States and three taxable corporate subsidiaries in Canada. The income tax provision reported in our consolidated statements of operations relates primarily to these subsidiaries.

A publicly-traded partnership is required to generate at least 90% of its gross income (as defined for federal income tax purposes) from certain qualifying sources. Income generated by our taxable corporate subsidiaries is excluded from this qualifying income calculation. Although we routinely generate income outside of our corporate subsidiaries that is non-qualifying, we believe that at least 90% of our gross income has been qualifying income for both of the calendar years since our initial public offering.

We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in the consolidated financial statements at June 30, 2013.

Note 9 — Commitments and Contingencies

Legal Contingencies

We are party to various claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of our management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of our liabilities may change materially as circumstances develop.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

Customer Dispute

A customer of our crude oil logistics segment has disputed the transportation rate schedule we used to bill the customer for services that we provided from November 2012 through February 2013, which was the same rate schedule that Pecos used to bill the customer from April 2011 through October 2012 (prior to our acquisition of Pecos). The customer has not paid $1.7 million of the amount we charged for services we provided from November 2012 through February 2013. In May 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. Later in May 2013, the customer filed an answer and counterclaim seeking to recover $5.5 million that it paid to Pecos prior to our acquisition of Pecos. We have not recorded revenue for the $1.7 million of unpaid fees charged subsequent to our acquisition of Pecos, pending resolution of the dispute. We are not able to reliably predict the outcome of this dispute at this time, but we do not believe the outcome will have a material adverse effect on our consolidated financial position or results of operations.

Canadian Fuel and Sales Taxes

The taxing authority of a province in Canada completed an audit of fuel and sales tax payments and concluded that High Sierra should have collected from customers and remitted to the taxing authority approximately $14.9 million of fuel taxes and sales taxes on certain historical sales. High Sierra had not collected and remitted fuel and sales taxes on these transactions, as High Sierra believed the transactions were exempt from these taxes. We are in the process of gathering information to support our position that the transactions were exempt from the taxes, which we believe could substantially reduce the amount of the tax assessed. If we are unsuccessful in demonstrating that these transactions were exempt, we would be required to remit payment to the taxing authority; however, we expect we would be able to recover these payments from the customers pursuant to the terms of our contracts with the customers. Although the outcome of this matter is not certain at this time, we do not believe the ultimate resolution of this matter will have a material adverse effect on our consolidated financial position or results of operations. We recorded in the acquisition accounting for the merger with High Sierra a liability of $14.9 million, which is the full amount assessed, and a receivable of $14.1 million, which represents the amount we would expect to recover from the customers in the event we are ultimately required to pay the taxes assessed.

Environmental Matters

Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there can be no assurance that significant costs will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

Asset Retirement Obligations

We have recorded an asset retirement obligation liability of $1.6 million at June 30, 2013. This liability is related to the wastewater disposal assets and crude oil pipeline injection facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certain other assets. However, we do not believe the present value of these asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of our facilities, is material to our consolidated financial position or results of operations.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

Operating Leases

We have executed various non-cancelable operating lease agreements for product storage, office space, vehicles, real estate, and equipment. Future minimum lease payments under contractual commitments as of June 30, 2013 are as follows (in thousands):

Year Ending March 31,
2014 (nine months)	$	43,468
2015	37,493
2016	31,376
2017	29,035
2018	21,542
Thereafter	39,329
Total	$	202,243

Rental expense relating to operating leases was $15.4 million during the three months ended June 30, 2013 and $4.8 million during the three months ended June 30, 2012.

Sales and Purchase Contracts

We have entered into sales and purchase contracts for natural gas liquids (including propane, butane, and ethane) and crude oil to be delivered in future periods. These contracts require that the parties physically settle the transactions with inventory. At June 30, 2013, we had the following such commitments outstanding:

	Volume	Value
	(in thousands )
Natural gas liquids fixed-price purchase commitments (gallons)	82,653	$	74,513
Natural gas liquids floating-price purchase commitments (gallons)	805,884	$	756,142
Natural gas liquids fixed-price sale commitments (gallons)	139,293	$	152,523
Natural gas liquids floating-price sale commitments (gallons)	533,918	$	578,277

Crude oil floating-price purchase commitments (barrels)	5,439	$	494,620
Crude oil floating-price sale commitments (barrels)	5,308	$	500,527

We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs.

Certain of the forward purchase and sale contracts shown in the table above were acquired in the June 2012 merger with High Sierra. We recorded these contracts at their estimated fair values at the merger date, and we are amortizing these assets and liabilities to cost of sales over the remaining terms of the contracts. During the three months ended June 30, 2013, our natural gas logistics segment recorded cost of sales of $1.4 million related to these contracts and our crude oil logistics segment recorded a reduction to cost of sales of $0.2 million related to these contracts. At June 30, 2013, the unamortized balances included in our consolidated balance sheet were as follows (in thousands):

Current assets	$	1,414
Current liabilities	(124		)
Net assets	$	1,290

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

Note 10 — Equity

Partnership Equity

The Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest. Limited partner equity includes common and subordinated units. The common and subordinated units share equally in the allocation of income or loss. The principal difference between common and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

The subordination period will end on the first business day after we have earned and paid the minimum quarterly distribution on each outstanding common unit and subordinated unit and the corresponding distribution on the general partner interest for each of three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2014. Also, if we have earned and paid at least 150% of the minimum quarterly distribution on each outstanding common unit and subordinated unit, the corresponding distribution on the general partner interest and the related distribution on the incentive distribution rights for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of removal. When the subordination period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages.

Our general partner is not obligated to make any additional capital contributions or to guarantee or pay any of our debts and obligations.

Distributions

Our general partner has adopted a cash distribution policy that will require us to pay a quarterly distribution to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner and its affiliates, referred to as “available cash,” in the following manner:

· First, 99.9% to the holders of common units and 0.1% to the general partner, until each common unit has received the specified minimum quarterly distribution, plus any arrearages from prior quarters.

· Second, 99.9% to the holders of subordinated units and 0.1% to the general partner, until each subordinated unit has received the specified minimum quarterly distribution.

· Third, 99.9% to all unitholders, pro rata, and 0.1% to the general partner.

The general partner will also receive, in addition to distributions on its 0.1% general partner interest, additional distributions based on the level of distributions to the limited partners. These distributions are referred to as “incentive distributions.”

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1% general partner interest, assume our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and has not transferred its incentive distribution rights and there are no arrearages on common units.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

							Marginal Percentage Interest In
	Total Quarterly						Distributions
	Distribution Per Unit						Unitholders		General Partner
Minimum quarterly distribution					$	0.337500	99.9	%	0.1	%
First target distribution	above	$	0.337500	up to	$	0.388125	99.9	%	0.1	%
Second target distribution	above	$	0.388125	up to	$	0.421875	86.9	%	13.1	%
Third target distribution	above	$	0.421875	up to	$	0.506250	76.9	%	23.1	%
Thereafter	above	$	0.506250				51.9	%	48.1	%

During the three months ended June 30, 2013, we distributed a total of $26.8 million ($0.4775 per common and subordinated limited partner unit and per general partner notional unit) to our unitholders of record as of April 25, 2013. This included an incentive distribution of $1.2 million to the general partner. On July 25, 2013, we declared a distribution of $0.4938 per common unit, to be paid on August 14, 2013 to unitholders of record on August 5, 2013. This distribution amounts to $33.5 million, including amounts to be paid on common, subordinated, and general partner notional units and the amount to be paid on incentive distribution rights.

Equity-Based Incentive Compensation

Our general partner has adopted a long-term incentive plan (the “LTIP”), which allows for the issuance of equity-based compensation to employees and directors. During the fiscal year ended March 31, 2013 and during the three months ended June 30, 2013, the board of directors of our general partner granted certain restricted units to employees and directors, which will vest in tranches, subject to the continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

The following table summarizes the restricted unit activity during the three months ended June 30, 2013:

Unvested restricted units at March 31, 2013	1,444,900
Units granted	300,500
Units forfeited	(5,000	)
Unvested restricted units at June 30, 2013	1,740,400

The scheduled vesting of the awards is summarized below:

Vesting Date		Number of Awards
July 1, 2013		398,800
January 1, 2014		20,000
July 1, 2014		397,800
January 1, 2015		12,000
July 1, 2015		319,300
January 1, 2016		12,000
July 1, 2016		310,500
January 1, 2017		12,000
July 1, 2017		216,000
January 1, 2018		12,000
July 1, 2018		30,000
Total unvested units at June 30, 2013		1,740,400

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

On July 1, 2013, 398,800 of the awards vested. We issued 282,689 common units to the recipients and we withheld 116,111 common units, in return for which we paid withholding taxes on behalf of the recipients.

We record the expense for each tranche on a straight-line basis over the period beginning with the vesting of the previous tranche and ending with the vesting of the tranche. We adjust the cumulative expense recorded through the reporting date using the estimated fair value of the awards at the reporting date. The weighted-average fair value of the awards was $26.15 at June 30, 2013, which was calculated as the closing price of the common units on June 30, 2013, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth.

We recorded $7.1 million of expense related to restricted unit awards during the three months ended June 30, 2013 and we recorded $0.6 million of expense related to restricted unit awards during the three months ended June 30, 2012. We estimate that the expense we will record on the unvested awards as of June 30, 2013 will be as follows (in thousands), after taking into consideration an estimate of forfeitures of approximately 76,000 units. For purposes of this calculation, we have used the closing price of the common units on June 30, 2013.

Year Ending March 31,
2014 (nine months)	$	9,338
2015	10,127
2016	9,167
2017	6,962
2018	2,339
2019	203
Total	$	38,136

Following is a rollforward of the liability related to equity-based compensation, which is reported within accrued expenses and other payables on our consolidated balance sheets (in thousands):

Balance at March 31, 2013	$	5,043
Expense recorded during the three months ended June 30, 2013	7,075
Balance at June 30, 2013	$	12,118

The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common and subordinated units. The maximum number of units deliverable under the plan automatically increases to 10% of the issued and outstanding common and subordinated units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount. Units withheld to satisfy tax withholding obligations will not be considered to be delivered under the LTIP. In addition, if an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available for new awards under the LTIP. As of June 30, 2013, approximately 3.5 million units remain available for issuance under the LTIP.

Note 11 — Fair Value of Financial Instruments

Our cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, and other current liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values due to their short-term nature. We believe the carrying amounts of our long-term debt instruments, including the Revolving Credit Facility and the Senior Notes, approximate their fair values, as we do not believe market conditions have changed materially since we entered into these debt agreements.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

Commodity Derivatives

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at June 30, 2013:

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	434		$	(4,593	)
Level 2 measurements	11,302			(15,890		)
	11,736			(20,483		)

Netting of counterparty contracts (1)	(4,297		)	4,297
Cash collateral provided	—			5,486
Commodity contracts reported on consolidated balance sheet	$	7,439		$	(10,700	)

(1) Relates to derivative assets and liabilities that are expected to be net settled on an exchange or through a master netting arrangement with the counterparty.

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2013:

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	947		$	(3,324	)
Level 2 measurements	9,911			(13,280		)
	10,858			(16,604		)

Netting of counterparty contracts (1)	(3,503		)	3,503
Cash collateral provided or held	(1,760		)	400
Commodity contracts reported on consolidated balance sheet	$	5,595		$	(12,701	)

(1) Relates to derivative assets and liabilities that are expected to be net settled on an exchange or through a master netting arrangement with the counterparty.

The commodity derivative assets (liabilities) are reported in the following accounts on the consolidated balance sheets:

	June 30,			March 31,
	2013			2013
	(in thousands)
Prepaid expenses and other current assets	$	7,216		$	5,551
Other noncurrent assets	223			44
Accrued expenses and other payables	(9,384		)	(12,701		)
Other noncurrent liabilities	(1,316		)	—
Net liability	$	(3,261	)	$	(7,106	)

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

The following table sets forth our open commodity derivative contract positions at June 30, 2013 and March 31, 2013. We do not account for these derivatives as hedges.

		Total		Fair Value
		Notional		of
		Units		Net Assets
Contracts	Settlement Period	(Barrels)		(Liabilities)
		(in thousands)
As of June 30, 2013 -
Butane cross-commodity (1)	July 2013 — March 2014	1,366		$	(13,218	)
Crude oil cross-commodity (2)	July 2013 — March 2014	(986	)	(2,732		)
Crude oil fixed-price (3)	July 2013 — March 2014	(270	)	4,521
Crude oil index (4)	July 2013 — June 2014	267		1,043
Propane fixed-price (5)	July 2013 — December 2014	(370	)	1,595
Other	July 2013 — March 2014	(43	)	44
				(8,747		)
Net cash collateral held				5,486
Net fair value of commodity derivatives on consolidated balance sheet				$	(3,261	)

As of March 31, 2013 -
Butane cross-commodity (1)	April 2013 — March 2014	1,546		$	(2,557	)
Crude oil cross-commodity (2)	April 2013 — March 2014	(1,116	)	(7,651		)
Crude oil fixed-price (3)	April 2013 — March 2014	(144	)	1,033
Crude oil index (4)	April 2013 — June 2014	(91	)	153
Propane fixed-price (5)	April 2013 — March 2014	(282	)	3,197
Other	May 2013 — June 2013	8		79
				(5,746		)
Net cash collateral held				(1,360		)
Net fair value of commodity derivatives on consolidated balance sheet				$	(7,106	)

(1) Butane cross-commodity – Our natural gas liquids logistics segment purchases or sells certain commodities for which the pricing mechanism is based on a different commodity. The contracts listed in this table as “Butane cross-commodity” represent financial derivatives we have entered into as an economic hedge against the risk of changes in butane prices relative to the price of the other commodity.

(2) Crude oil cross-commodity – Our natural gas liquids logistics segment purchases or sells certain commodities for which the pricing mechanism is based on a different commodity. The contracts listed in this table as “Crude oil cross-commodity” represent financial derivatives we have entered into as an economic hedge against the risk of changes in crude prices relative to the price of the other commodity.

(3) Crude oil fixed-price – Our crude oil logistics segment routinely purchases crude oil inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Crude oil fixed-price” represent financial derivatives we have entered into as an economic hedge against the risk that crude oil prices will decline while we are holding the inventory.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

(4) Crude oil index – Our crude oil logistics segment routinely enters into crude oil purchase and sale contracts that are priced based on an index. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. The contracts listed in this table as “Crude oil index” represent financial derivatives entered into as economic hedges against the risk that changes in the different index prices would reduce the margins between the purchase and the sale transactions.

(5) Propane fixed-price – Our natural gas liquids logistics segment routinely purchases propane inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Propane fixed-price” represent financial derivatives we have entered into as an economic hedge against the risk that propane prices will decline while we are holding the inventory.

We recorded the following net gains (losses) from our commodity and interest rate derivatives during the periods indicated:

	Three Months Ended June 30,
	2013			2012
	(in thousands)
Commodity contracts -
Unrealized gain (loss)	$	(3,578	)	$	1,929
Realized gain (loss)	(3,631		)	2,299
Interest rate swaps	—			(1		)
Total	$	(7,209	)	$	4,227

The commodity contract gains and losses are included in cost of sales in the consolidated statements of operations.

Interest Rate Swap Agreement

We have entered into an interest rate swap agreement to hedge the risk of interest rate fluctuations on our long-term debt. This agreement effectively converts a portion of our floating rate debt into fixed rate debt on a notional amount of $8.5 million and ends on December 31, 2013. The notional amounts of derivative instruments do not represent actual amounts exchanged between the parties, but instead represent amounts on which the contracts are based. We recorded a liability of less than $0.1 million at June 30, 2013 and March 31, 2013 related to this agreement.

Credit Risk

We maintain credit policies with regard to our counterparties on the derivative financial instruments that we believe minimize our overall credit risk, including an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single counterparty.

Our counterparties consist primarily of financial institutions and energy companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

As is customary in the crude oil industry, we generally receive payment from customers for sales of crude oil on a monthly basis. As a result, receivables from individual customers in our crude business are generally higher than the receivables from customers in our other segments.

Failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated statements of financial position and recognized in our net income.

Interest Rate Risk

The interest rate on our Revolving Credit Facility floats based on market indices. At June 30, 2013, we had $493.0 million of debt on our Revolving Credit Facility at a rate of 3.2% and $27.5 million of debt on our Revolving Credit Facility at a rate of 5.25%. A change of 0.125% in the interest rate would result in a change to annual interest expense of approximately $0.7 million on the revolving debt balance of $520.5 million.

Note 12 — Segments

Our reportable segments are based on the way in which our management structure is organized. Certain financial data related to our segments is shown below. Transactions between segments are recorded based on prices negotiated between the segments.

Our crude oil logistics segment sells crude oil and provides crude oil transportation services to wholesalers, refiners, and producers. These operations began with our June 2012 merger with High Sierra.

Our water services segment provides services for the transportation, treatment, and disposal of wastewater generated from oil and natural gas production, and generates revenue from the sale of recycled wastewater and recovered hydrocarbons. These operations began with our June 2012 merger with High Sierra.

Our natural gas liquids logistics segment supplies propane and other natural gas liquids, and provides natural gas liquids transportation, terminaling, and storage services to retailers, wholesalers, and refiners. This segment includes our historical natural gas liquids operations and the natural gas liquids operations acquired in the June 2012 merger with High Sierra. We previously reported our natural gas liquids operations in two segments, referred to as our “wholesale marketing and supply” and “midstream” segments. The data in the table below has been presented under our new structure for both periods, with the amounts previously reported in the wholesale marketing and supply and midstream segments reported on a combined basis within the natural gas liquids logistics segment.

Our retail propane segment sells propane and distillates to end users consisting of residential, agricultural, commercial, and industrial customers, and to certain re-sellers. Our retail propane segment consists of two divisions, which are organized based on the location of the operations.

Items labeled “corporate and other” in the table below include the operations of a compressor leasing business that we acquired in our June 2012 merger with High Sierra, and also include certain corporate expenses that are incurred and are not allocated to the reportable segments. This data is included to reconcile the data for the reportable segments to data in our consolidated financial statements.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

	Three Months Ended June 30,
	2013			2012
	(in thousands)
Revenues:
Crude oil logistics -
Crude oil sales	$	928,534		$	73,364
Other revenues	9,935			514
Water services -
Water treatment and disposal	18,688			1,512
Water transportation	1,825			429
Natural gas liquids logistics -
Propane sales	123,837			105,844
Other natural gas liquids sales	249,853			95,416
Other revenues	8,864			2,826
Retail propane -
Propane sales	46,691			39,852
Distillate sales	17,869			11,764
Other retail sales	7,700			7,592
Other	1,474			153
Elimination of intersegment sales	(29,313		)	(12,830		)
Total revenues	$	1,385,957		$	326,436

Depreciation and Amortization:
Crude oil logistics	$	4,684		$	260
Water services	7,356			282
Natural gas liquids logistics	2,704			1,897
Retail propane	7,240			6,741
Other	740			47
Total depreciation and amortization	$	22,724		$	9,227

Operating Income (Loss):
Crude oil logistics	$	6,609		$	(4,310	)
Water services	3,043			170
Natural gas liquids logistics	(2,115		)	1,185
Retail propane	(1,504		)	(6,171		)
Corporate and other	(13,375		)	(5,948		)
Total operating loss	$	(7,342	)	$	(15,074	)

Other items not allocated by segment:
Interest expense	(10,622		)	(3,800		)
Loss on early extinguishment of debt	—			(5,769		)
Interest income	398			366
Other income, net	(348		)	26
Income tax (expense) benefit	406			(459		)
Net loss	$	(17,508	)	$	(24,710	)

Additions to property, plant and equipment, including acquisitions (accrual basis):
Crude oil logistics	$	4,126		$	25,478
Water services	7,709			91,778
Natural gas liquids logistics	15,107			2,111
Retail propane	6,946			54,711
Other	629			12,144
Total	$	34,517		$	186,222


	June 30,		March 31,
	2013		2013
	(in thousands)
Total assets:
Crude oil logistics	$	800,627	$	801,030
Water services	466,033		466,462
Natural gas liquids logistics	555,269		474,141
Retail propane	488,845		513,301
Corporate	42,527		36,413
Total	$	2,353,301	$	2,291,347

Long-lived assets, net:
Crude oil logistics	$	356,033	$	356,750
Water services	453,925		453,986
Natural gas liquids logistics	249,221		238,192
Retail propane	442,670		441,762
Corporate	32,649		31,996
Total	$	1,534,498	$	1,522,686

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

Note 13 — Transactions with Affiliates

Since our business combination with SemStream on November 1, 2011, SemGroup Corporation (“SemGroup”) has held ownership interests in us and in our general partner, and has had the right to appoint two members to the Board of Directors of our general partner. Subsequent to November 1, 2011, our natural gas liquids logistics segment has sold natural gas liquids to and purchased natural gas liquids from affiliates of SemGroup. These transactions are included within revenues and cost of sales of our natural gas liquids logistics business in our consolidated statements of operations. We also made payments to SemGroup for certain administrative and operational services. These transactions are reported within operating and general and administrative expenses in our consolidated statements of operations.

Certain members of management of High Sierra who joined our management team upon completion of the June 19, 2012 merger with High Sierra own interests in several entities. Subsequent to this business combination with High Sierra, we have purchased products and services from and have sold products and services to these entities. The majority of these purchases represent crude oil purchases and are reported within cost of sales in our consolidated statements of operations, although approximately $2.0 million of these transactions during the three months ended June 30, 2013 represented capital expenditures and were recorded as increases to property, plant and equipment. The majority of these sales represent sales of crude oil and have been recorded within revenues in our consolidated statement of operations. In addition, our retail operations purchased goods and services from certain entities owned by our executive officers and their family members.

These transactions are summarized in the table below (in thousands):

	Three Months Ended June 30,
	2013		2012

Sales to SemGroup	$	—	$	12,682
Purchases from SemGroup	19,539		12,548
Sales to entities affiliated with High Sierra management	51,103		189
Purchases from entities affiliated with High Sierra management	7,615		1,756
Purchases from entities affiliated with retail segment management	209		87

Receivables from affiliates at June 30, 2013 and March 31, 2013 consist of the following (in thousands):

	June 30,		March 31,
	2013		2013

Receivables from entities affiliated with High Sierra management	$	14,397	$	22,787
Other	82		96
	$	14,479	$	22,883

Payables to related parties at June 30, 2013 and March 31, 2013 consist of the following (in thousands):

	June 30,		March 31,
	2013		2013

Payables to SemGroup	$	8,419	$	4,601
Payables to entities affiliated with High Sierra management	2,069		2,299
Other	16		—
	$	10,504	$	6,900

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

As of June 30, 2013 and March 31, 2013, and for the

Three Months Ended June 30, 2013 and 2012

As described in Note 1, we completed a merger with High Sierra Energy, LP and High Sierra Energy GP, LLC in June 2012, which involved certain transactions with our general partner. We paid $91.8 million of cash, net of $5.0 million of cash acquired, and issued 18,018,468 common units to acquire High Sierra Energy, LP. We also paid $97.4 million of High Sierra Energy, LP’s long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our general partner.

Note 14 — Subsequent Events

Equity Offering

On July 5, 2013, we completed a public offering of 10,350,000 common units. We received net proceeds of approximately $287.5 million, after underwriting discounts and commissions of $12.0 million and estimated offering costs of $0.7 million. We used the majority of the net proceeds from the offering to reduce the balance on our Revolving Credit Facility.

Acquisitions Subsequent to June 30, 2013

On August 2, 2013, we completed the acquisition of seven entities affiliated with Oilfield Water Lines LP (“OWL”) to expand our water services operations in Texas. We issued 2,463,287 common units, valued at $69.0 million, and paid approximately $168.0 million of cash to acquire these entities. The acquisition agreement contemplates a post-closing adjustment to the purchase price for certain specified working capital items. The acquisition agreement also includes a provision whereby the purchase price may be increased if certain performance targets are achieved during the six months following the acquisition. The maximum potential increase to the purchase price under this provision is $60 million.

During July 2013, we completed three separate acquisitions. These included a crude oil barge transportation and terminalling business in South Texas, and water disposal business in West Texas, and a retail propane business in Illinois. On a combined basis, we issued 175,211 common units, valued at $5.3 million, and paid $98.2 million in cash to acquire these businesses. The acquisition agreements contemplate post-closing adjustments to the purchase prices for certain specified working capital items.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following is a discussion of our financial condition and results of operations as of and for the three months ended June 30, 2013. The discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the historical consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2013.

Overview

NGL Energy Partners LP (“we”, “us”, “our”, or the “Partnership”) is a Delaware limited partnership formed in September 2010. NGL Energy Holdings LLC serves as our general partner. At the time of formation, our operations included a wholesale natural gas liquids business and a retail propane business. We completed an initial public offering in May 2011. Subsequent to our initial public offering, we significantly expanded our operations through a number of business combinations, including the following:

· On October 3, 2011, we completed a business combination with E. Osterman Propane, Inc., its affiliated companies and members of the Osterman family, whereby we acquired retail propane operations in the northeastern United States.

· On February 3, 2012, we completed a business combination with North American Propane, Inc., whereby we acquired retail propane and distillate operations in the northeastern United States.

· During the year ended March 31, 2012, we completed three additional separate business combination transactions to acquire retail propane operations.

· During the year ended March 31, 2013, we completed four additional separate acquisitions to expand the assets and operations of our crude oil logistics and water services businesses.

· During the three months ended June 30, 2013, we completed two acquisitions of retail propane and distillate businesses.

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As of June 30, 2013, our businesses include:

Crude Oil Logistics

Our crude oil transportation and marketing 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” contractual agreements 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 well head 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 to different markets. We also seek to maximize margins by blending crude oil of varying properties.

The range of high and low spot prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma for the period indicated and the prices as of period end are as follows:

	Spot Price Per Barrel
					At Period
	Low		High		End

For the three months ended June 30, 2013	$	86.68	$	98.44	$	96.56

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

Water Services

Our water services 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 services 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

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primary customers of our facilities in Colorado have committed to deliver to our facilities all wastewater produced at wells in a designated area. The customers of our other facilities are not under volume commitments.

Natural Gas Liquids Logistics

Our natural gas liquids logistics segment purchases propane, butane, and other natural gas liquids from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets. Our natural gas liquids logistics segment owns 17 terminals and operates a fleet of owned and leased rail cars and leases underground storage capacity. We attempt to reduce our exposure to the impact of price fluctuations by using “back-to-back” contractual agreements and “pre-sale” agreements that essentially 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 as a percentage of revenues or on a per gallon basis than our retail propane business.

Weather conditions 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.

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

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

For the Three Months Ended:
June 30, 2013	$	0.77	$	0.91	$	0.80	$	0.81	$	0.97	$	0.85
June 30, 2012	0.50		0.96		0.54		0.71		1.22		0.82

The range of high and low spot butane prices per gallon at Mt. Belvieu, Texas are shown below for the periods indicated:

	Spot Price Per Gallon
	Low		High		At Period End
For the Three Months Ended:
June 30, 2013	$	1.08	$	1.41	$	1.18
June 30, 2012	1.14		1.93		1.22

We believe volatility in commodity prices will continue, and our ability to adjust to 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 natural gas liquids logistics 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 have a

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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 and distillate 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 costs, we have typically 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. Approximately 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.

Recent Developments

Equity Offering

Acquisitions Subsequent to June 30, 2013

Summary Discussion of Operating Results for the Three Months ended June 30, 2013

During the three months ended June 30, 2013, we generated an operating loss of $7.3 million, compared to an operating loss of $15.1 million during the three months ended June 30, 2012.

Our crude oil logistics segment generated operating income of $6.6 million during the three months ended June 30, 2013. This operating income was lower than for the three-month periods ended March 31, 2013, December 31, 2012, and June 30, 2012, due primarily to a narrowing of the price differences between markets, which reduced our opportunities to generate increased margins by transporting product from lower-price to higher-price markets.

Our water services segment generated operating income of $3.0 million during the three months ended June 30, 2013. This amount is relatively consistent with the operating income generated during the three-month periods ended March 31, 2013 and December 31, 2012.

Our natural gas liquids logistics business generated an operating loss of $2.1 million during the three months ended June 30, 2013, compared to operating income of $1.2 million during the three months ended June 30, 2012. Due to the seasonal nature of demand for natural gas liquids, sales volumes of our natural gas liquids logistics business 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 business generated an operating loss of $1.5 million during the three months ended June 30, 2013, compared to an operating loss of $6.2 million during the three months ended June 30, 2012. Due to the seasonal nature of demand for natural gas liquids, sales volumes of our retail propane business are lower during the first and second quarters of the

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fiscal year than during the third and fourth quarters of the fiscal year. The lower operating loss during the three months ended June 30, 2013, compared to the operating loss during the three months ended June 30, 2012, was due primarily to more favorable weather patterns. Synergies resulting from the integration of acquired businesses also contributed to the improved operating results.

We incurred interest expense of $10.6 million during the three months ended June 30, 2013. This was higher than the interest expense during the three months ended June 30, 2012, due primarily to borrowings during fiscal 2013 to finance acquisitions.

Consolidated Results of Operations

The following table summarizes our historical unaudited consolidated statements of operations for the three months ended June 30, 2013 and 2012.

	Three Months Ended June 30,
	2013			2012
	(in thousands)
Revenues	$	1,385,957		$	326,436
Cost of sales	1,303,076			298,985
Operating and general and administrative expenses	67,499			33,298
Depreciation and amortization	22,724			9,227
Operating loss	(7,342		)	(15,074		)
Interest expense	(10,622		)	(3,800		)
Loss on early extinguishment of debt	—			(5,769		)
Interest and other income	50			392
Loss before income taxes	(17,914		)	(24,251		)
Income tax (provision) benefit	406			(459		)
Net loss	(17,508		)	(24,710		)
Net income allocated to general partner	(1,688		)	(95		)
Net (income) loss attributable to noncontrolling interests	(125		)	60
Net loss attributable to parent equity allocated to limited partners	$	(19,321	)	$	(24,745	)

See the detailed discussion of revenues, cost of sales, operating expenses, general and administrative expenses, depreciation and amortization and operating income by operating segment below. The business combination with High Sierra and the subsequent acquisitions of crude oil logistics and water services businesses described above had a significant impact on the comparability of our results of operations for the three months ended June 30, 2013 and 2012.

Set forth below is a discussion of significant changes in the non-segment related corporate other income and expenses during the respective periods.

Interest Expense

The largest component of interest expense during the three months ended June 30, 2013 and 2012 has been interest on revolving credit facilities and on senior notes that we issued in June 2012. See Note 7 to our consolidated financial statements included elsewhere in this Quarterly Report for additional information on our long-term debt. The change in interest expense during the periods presented is due primarily to fluctuations in the average outstanding debt balance, as summarized below:

	Average Debt				Average Debt
	Balance				Balance
	Outstanding -		Average		Outstanding -
	Revolving Facilities		Interest Rate -		Senior Notes		Interest Rate -
	(in thousands)		Revolving Facilities		(in thousands)		Senior Notes

Three Months Ended June 30,
2013	$	469,489	3.66	%	$	250,000	6.65	%
2012	$	274,114	3.81	%	$	32,967	6.65	%

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Interest expense also includes amortization of debt issuance costs, which represented $1.4 million of expense during the three months ended June 30, 2013 and $0.5 million of expense during the three months ended June 30, 2012. Interest expense also includes letter of credit fees, interest on equipment financing notes, and accretion of interest on non-interest bearing debt obligations assumed in business combinations.

On June 19, 2012, we retired our previous revolving credit facility. Upon retirement of this facility, we wrote off the portion of the debt issuance cost asset that had not yet been amortized. This expense is reported as “Loss on early extinguishment of debt” in our consolidated statement of operations.

The increased level of debt outstanding during the three months ended June 30, 2013 is due primarily to borrowings to finance acquisitions.

Income Tax Provision

See Note 8 to our consolidated financial statements included elsewhere in this annual report for additional description of income tax provisions.

Noncontrolling Interests

As of June 30, 2013, we have three consolidated subsidiaries in which outside parties own interests. Our ownership interests in these subsidiaries range from 60% to 80%. The noncontrolling interest shown in our consolidated statements of operations represents the other owners’ share of the net income of these entities.

Non-GAAP Financial Measures

The following table reconciles net loss attributable to parent equity to our EBITDA and Adjusted EBITDA, each of which are non-GAAP financial measures, for the periods indicated:

	Three Months Ended June 30,
	2013			2012
	(in thousands)
EBITDA:
Net loss attributable to parent equity	$	(17,633	)	$	(24,650	)
Provision (benefit) for income taxes	(406		)	459
Interest expense	10,622			3,800
Loss on early extinguishment of debt	—			5,769
Depreciation and amortization expense	23,195			9,414
EBITDA	$	15,778		$	(5,208	)
Unrealized (gain) loss on derivative contracts	3,578			(1,929		)
Loss on sale of assets	373			7
Share-based compensation expense	7,075			655
Adjusted EBITDA	$	26,804		$	(6,475	)

We define EBITDA as net income (loss) attributable to parent equity, plus income taxes, interest expense and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding the unrealized gain or loss on derivative contracts, the gain or loss on the disposal of assets, and share-based compensation expenses. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP as those items are used to measure operating performance, liquidity, or the ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make

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quarterly distributions to our unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other entities.

Segment Operating Results for the Three Months Ended June 30, 2013 and 2012

Items Impacting the Comparability of Our Financial Results

Our results of operations for the three months ended June 30, 2013 may not be comparable to our results of operations for the three months ended June 30, 2012, due to the business combinations described above. The results of operations of our natural gas liquids businesses are impacted by seasonality, primarily due to the increase in volumes sold by our retail and wholesale natural gas liquids businesses during the peak heating season of October through March. In addition, product price fluctuations can have a significant impact on our sales volumes. For these and other reasons, our results of operations for the three months ended June 30, 2013 are not necessarily indicative of the results to be expected for the full fiscal year.

Volumes Sold or Delivered

The following table summarizes the volume of product sold and wastewater delivered for the three months ended June 30, 2013, and 2012, respectively. Volumes shown in the table below for our natural gas liquids logistics segment include sales to our retail segment.

	Three Months Ended June 30,
Segment	2013	2012	Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)	9,255	881	8,374

Water services
Water delivered (barrels)	10,039	731	9,308

Natural gas liquids logistics
Propane sold (gallons)	127,419	118,915	8,504
Other natural gas liquids sold (gallons)	249,252	64,955	184,297

Retail propane
Propane sold (gallons)	23,393	19,270	4,123
Distillates sold (gallons)	5,104	3,249	1,855

The increase in volumes of our crude oil logistics and water services segments is due primarily to the fact that we did not own these businesses until our June 19, 2012 merger with High Sierra. During the quarter ended June 30, 2012, the crude oil logistics and water services businesses were only included in our results of operations for the last eleven days of the quarter. In addition, we completed several subsequent acquisitions of crude oil logistics and water services businesses, including Pecos (completed in November 2012) and Third Coast (completed in December 2012), among others.

The increase in volumes sold by our natural gas liquids logistics business is due primarily to the June 19, 2012 merger with High Sierra.

The increase in volumes sold by our retail propane segment was due primarily to changes in weather conditions. Due to mild weather conditions during fiscal 2012, our customers had higher than normal levels of product on hand at the end of the winter season, which reduced demand during the three months ended June 30, 2012. The increase in volume sold is also attributable to acquisitions during fiscal 2013, primarily the May 1, 2012 acquisition of the assets and operations of Downeast Energy Corp (“Downeast”).

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Operating Income (Loss) by Segment

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

	Three Months Ended June 30,
Segment	2013			2012			Change
	(in thousands)
Crude oil logistics	$	6,609		$	(4,310	)	$	10,919
Water services	3,043			170			2,873
Natural gas liquids logistics	(2,115		)	1,185			(3,300		)
Retail propane	(1,504		)	(6,171		)	4,667
Corporate and other	(13,375		)	(5,948		)	(7,427		)
Operating loss	$	(7,342	)	$	(15,074	)	$	7,732

The operating loss within “corporate and other” for the three months ended June 30, 2013 includes approximately $7.1 million of expense related to equity-based compensation, approximately $0.6 million of expenses related to acquisitions, and approximately $5.4 million of other corporate expenses.

The operating loss within “corporate and other” for the three months ended June 30, 2012 includes approximately $0.6 million of expense related to equity-based compensation, approximately $3.8 million of expenses related to acquisitions, and approximately $1.5 million of other corporate expenses.

The increase in equity-based compensation expense is due to the timing of the grants. Most of the restricted unit awards were granted in June 2012 and December 2012, and the expense is recorded over the vesting period of the awards.

The decrease in acquisition-related expenses is due primarily to the fact that $3.5 million of expense recorded during the three months ended June 30, 2012 related to the merger with High Sierra. This merger was completed on June 19, 2012.

The increase in other corporate expenses is due primarily to increases in compensation expense, due to the addition of new corporate employees. This includes employees of High Sierra who joined us after the merger, and also includes new employees subsequently added to provide general and administrative services in support of the growth of our business.

The operations of our compressor leasing business, which was acquired in our merger with High Sierra, are also included within “corporate and other.”

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Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the three months ended June 30, 2013 and 2012 (amounts in thousands). The operations of our crude oil logistics segment began with our June 19, 2012 merger with High Sierra.

	Three Months Ended June 30,
	2013		2012
Revenues:
Crude oil sales	$	928,534	$	73,364
Other revenues	9,935		514
Total revenues(1)	938,469		73,878
Expenses:
Cost of sales	916,894		77,244
Operating expenses	9,415		610
General and administrative expenses	867		74
Depreciation and amortization expense	4,684		260
Total expenses	931,860		78,188
Segment operating income (loss)	$	6,609	$	(4,310	)

(1) Revenues include $1.4 million of intersegment sales during the three months ended June 30, 2013 that are eliminated in our consolidated statement of operations.

Revenue. We generated revenue of $928.5 million from crude oil sales during the three months ended June 30, 2013, selling 9.3 million barrels at an average price of $100.33 per barrel. We also generated $9.9 million of revenue from the transportation of crude oil owned by other parties and other services. During the three months ended June 30, 2012, we generated revenue of $73.4 million from crude oil sales, selling 0.9 million barrels at an average price of $83.27 per barrel. Our crude oil logistics business began with our June 19, 2012 merger with High Sierra; we only owned this business for the last eleven days of the quarter ended June 30, 2012.

Cost of Sales. Our cost of crude oil sold was $916.9 million during the three months ended June 30, 2013. We sold 9.3 million barrels at an average cost of $99.07 per barrel. Our cost of sales during the three months ended June 30, 2013 was reduced by $4.6 million of unrealized gains on derivatives. During the three months ended June 30, 2012, our cost of crude oil sold was $77.2 million. We sold 0.9 million barrels at an average cost of $87.68 per barrel. Our crude oil logistics business began with our June 19, 2012 merger with High Sierra; we only owned this business for the last eleven days of the quarter ended June 30, 2012. Our cost of sales during the three months ended June 30, 2012 was increased by $3.0 million of losses on derivatives.

Other Operating Expenses. Our crude oil operations generated $10.3 million of operating and general and administrative expenses during the three months ended June 30, 2013. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $4.7 million during the three months ended June 30, 2013. These expenses were higher than during the three months ended June 30, 2012, due primarily to the fact that we only owned the assets and operations of the crude oil segment for the last eleven days of the quarter ended June 30, 2012.

Operating income (loss). Our crude oil logistics segment generated operating income of $6.6 million during the three months ended June 30, 2013, compared to an operating loss of $4.3 million during the three months ended June 30, 2012. The operating loss during the three months ended June 30, 2012 included $3.0 million of losses on derivatives.

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Water Services

The following table summarizes the operating results of our water services segment for the three months ended June 30, 2013 and 2012 (amounts in thousands). The operations of our water services segment began with our June 19, 2012 combination with High Sierra.

	Three Months Ended June 30,
	2013		2012
Revenues:
Water treatment and disposal (1)	$	18,688	$	1,512
Water transportation	1,825		429
Total revenues	20,513		1,941
Expenses:
Cost of sales	583		616
Operating expenses	9,007		804
General and administrative expenses	524		69
Depreciation and amortization expense	7,356		282
Total expenses	17,470		1,771
Segment operating income	$	3,043	$	170

(1) Revenues include $6.3 million of intersegment sales during the three months ended June 30, 2013 that are eliminated in our consolidated statement of operations.

Revenues. Our water services segment generated $18.7 million of treatment and disposal revenue during the three months ended June 30, 2013, taking delivery of 10.0 million barrels of wastewater at an average revenue of $1.86 per barrel. Our water transportation business generated $1.8 million of revenues during the three months ended June 30, 2013. During the three months ended June 30, 2012, our water services segment generated $1.5 million of treatment and disposal revenue, taking delivery of 0.7 million barrels of wastewater at an average revenue of $2.07 per barrel, and our wastewater transportation business generated $0.4 million of revenue. Our water services business began with our June 19, 2012 merger with High Sierra; we only owned this business for the last eleven days of the quarter ended June 30, 2012.

Cost of Sales. The cost of sales for our water services segment was $0.6 million for the three months ended June 30, 2013. Cost of sales was reduced by net gains of $0.3 million on derivatives, which consisted of $0.6 million of unrealized gains partially offset by $0.3 million of realized losses. Because a portion of our processing revenue is generated from the sale of recovered hydrocarbons, we enter into derivatives to protect against the risk of a decline in the market price of a portion of the hydrocarbons we expect to recover. During the three months ended June 30, 2012, the cost of sales for our water services segment was $0.6 million, which consisted primarily of $0.4 million of losses on derivatives. Our water services business began with our June 19, 2012 merger with High Sierra; we only owned this business for the last eleven days of the quarter ended June 30, 2012.

Other Operating Expenses. Our water services segment generated $9.5 million of operating and general and administrative expenses during the three months ended June 30, 2013. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $7.4 million during the three months ended June 30, 2013. These expenses were higher than during the three months ended June 30, 2012, due primarily to the fact that we only owned the assets and operations of the water services segment for the last eleven days of the quarter ended June 30, 2012.

Operating income. Our water services segment generated $3.0 million of operating income during the three months ended June 30, 2013, compared to operating income of $0.2 million during the three months ended June 30, 2012. The increase operating income was due primarily to the fact that the this segment was only included in our results of operations for eleven days during the three months ended June 30, 2012, and was also due to an acquisition of an additional water services business in October 2012 and to our drilling of new disposal wells.

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Natural Gas Liquids Logistics

The following table compares the operating results of our natural gas liquids logistics segment for the periods indicated:

	Three Months Ended June 30,
	2013			2012		Change
	(in thousands)
Revenues:
Propane sales	$	123,837		$	105,844	$	17,993
Other natural gas liquids sales	249,853			95,416		154,437
Other revenues	8,864			2,826		6,038
Total revenues (1)	382,554			204,086		178,468

Expenses:
Cost of sales - propane	117,543			96,291		$	21,252
Cost of sales - other NGLs	248,935			97,853		151,082
Cost of sales - storage	5,368			2,370		2,998
Operating expenses	8,732			3,378		5,354
General and administrative expenses	1,387			1,112		275
Depreciation and amortization expense	2,704			1,897		807
Total expenses	384,669			202,901		181,768

Segment operating income (loss)	$	(2,115	)	$	1,185	$	(3,300	)

(1) The revenues in this table include $21.5 million of sales to our retail propane segment during the three months ended June 30, 2013 and $12.5 million of sales to our retail propane segment during the three months ended June 30, 2012. These intercompany sales, along with a corresponding amount of cost of sales, are eliminated in our consolidated statements of operations.

Revenues. Revenues from wholesale propane sales increased approximately $18.0 million during the three months ended June 30, 2013, as compared to $105.8 million during the three months ended June 30, 2012. This resulted from an increase in the volume sold of 8.5 million gallons, as compared to 118.9 million gallons sold during the three months ended June 30, 2012, and an increase is the sales price per gallon of $0.08 per gallon, as compared to $0.89 per gallon during the three months ended June 30, 2012. An increase in volume of approximately 17.6 million gallons was attributable to the inclusion of High Sierra in the results of operations for the full quarter ended June 30, 2013; High Sierra was only included in the results of operations for the last eleven days of the quarter ended June 30, 2012 that was subsequent to the merger. Volumes also benefitted from the refurbishment during the fiscal year ended March 31, 2013 of two terminals that had been acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

Revenues from wholesale sales of other natural gas liquids increased approximately $154.4 million during the three months ended June 30, 2013, as compared to $95.4 million during the three months ended June 30, 2012. This resulted from an increase in volume sold of 184.3 million gallons, as compared to 65.0 million gallons sold during the three months ended June 30, 2012, partially offset by a decrease in the sales price per gallon of $0.47 per gallon, as compared to $1.47 per gallon during the three months ended June 30, 2012. Approximately 169.5 million gallons of the volume increase was attributable to the inclusion of High Sierra in the results of operations for the full quarter ended June 30, 2013; High Sierra was only included in the results of operations for the last eleven days of the quarter ended June 30, 2012 that occurred after the date of the merger. The remaining increase in volume was due to increased demand, which resulted from the fact that the weather during the most recent winter was colder than during the preceding winter. The decline in selling price per gallon is due primarily to a decline in the market price for butane during the three months ended June 30, 2013 compared to the three months ended June 30, 2012.

Cost of Sales. Costs of wholesale propane sales increased approximately $21.3 million during the three months ended June 30, 2013, as compared to $96.3 million during the three months ended June 30, 2012. This resulted from an increase in the volume sold of 8.5 million gallons, as compared to 118.9 million gallons sold during the three months ended June 30, 2012 and an increase in the cost of $0.11 per gallon, as compared to $0.81 per gallon during the three months ended June 30, 2012. Cost of propane sales during the three months ended June 30, 2013 were reduced by $1.2 million of net gains on derivatives, which included $2.8 million of realized gains, partially offset by $1.6 million of unrealized losses. Cost of propane sales during the three months ended June 30, 2012 were reduced by $13.0 million of unrealized gains and $1.1 million of realized gains on derivatives.

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Cost of wholesale sales of other natural gas liquids increased approximately $151.1 million during the three months ended June 30, 2013, as compared to $97.9 million during the three months ended June 30, 2012. This resulted from an increase in volume of approximately 184.3 million gallons as compared to 65.0 million gallons sold during the three months ended June 30, 2012, partially offset by a decrease in the average cost of $0.51 per gallon, as compared to $1.51 per gallon in the prior year. Cost of sales of other natural gas liquids during the three months ended June 30, 2013 were increased by $7.2 million of unrealized losses and $6.0 million of realized losses on derivatives. Cost of sales of other natural gas liquids during the three months ended June 30, 2012 were increased by $5.0 million of unrealized losses and $0.5 million of realized losses on derivatives.

Operating Expenses. Operating expenses of our natural gas liquids logistics segment increased approximately $5.4 million during the three months ended June 30, 2013 as compared to operating expenses of $3.4 million during the three months ended June 30, 2012. The increase in operating expenses is due primarily to the natural gas liquids business of High Sierra, which was only included in our results of operations for the last eleven days of the quarter ended June 30, 2012, and to increased employee compensation costs.

General and Administrative Expenses. General and administrative expenses of our natural gas liquids logistics segment increased approximately $0.3 million during the three months ended June 30, 2013 as compared to general and administrative expenses of $1.1 million during the three months ended June 30, 2012. This was due to the inclusion of the natural gas liquids business of High Sierra in the results of operations for the full three months ended June 30, 2013.

Depreciation and amortization expense. Depreciation and amortization expense of our natural gas liquids logistics segment increased approximately $0.8 million during the three months ended June 30, 2013, as compared to depreciation and amortization expense of approximately $1.9 million during the three months ended June 30, 2012.

Operating Income (Loss). Our natural gas liquids logistics segment had an operating loss of approximately $2.1 million during the three months ended June 30, 2013 as compared to operating income of $1.2 million during the three months ended June 30, 2012. Although revenues were higher during the three months ended June 30, 2013 than during the three months ended June 30, 2012, product margins per gallon were lower and operating and general and administrative expenses were higher.

Retail Propane

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

	Three Months Ended June 30,
	2013			2012			Change
	(in thousands)
Revenues:
Propane sales	$	46,691		$	39,852		$	6,839
Distillate sales	17,869			11,764			6,105
Other revenues	7,700			7,592			108
Total revenues	72,260			59,208			13,052
Expenses:
Cost of sales - propane	25,179			23,193			1,986
Cost of sales - distillates	15,244			11,621			3,623
Cost of sales - other	2,643			2,627			16
Operating expenses	20,842			18,442			2,400
General and administrative expenses	2,616			2,755			(139		)
Depreciation and amortization expense	7,240			6,741			499
Total expenses	73,764			65,379			8,385

Segment operating loss	$	(1,504	)	$	(6,171	)	$	4,667

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Revenues. Propane sales for the three months ended June 30, 2013 increased approximately $6.8 million as compared to propane sales of $39.9 million during the three months ended June 30, 2012. Propane sales revenues were higher during the three months ended June 30, 2013 than during the three months ended June 30, 2012, due primarily to an increase in volume sold of 4.1 million gallons, compared to a volume sold of 19.3 million gallons during the three months ended June 30, 2012. The increase in volumes sold was due primarily to colder weather conditions during late fiscal 2013 than during late fiscal 2012. Due to mild weather conditions during fiscal 2012, our customers had higher than normal levels of product on hand at the end of the winter season, which reduced demand during the three months ended June 30, 2012. The increase in volume sold is also attributable to acquisitions during fiscal 2013, including the May 1, 2012 acquisition of Downeast. The increase in revenue resulting from higher volumes was partially offset by a decrease in revenue resulting from a decrease in the average selling price of $0.07 per gallon, as compared to an average selling price of $2.07 per gallon during the three months ended June 30, 2012.

Distillate sales for the three months ended June 30, 2013 increased approximately $6.1 million as compared to distillate sales of $11.8 million during the three months ended June 30, 2012, due primarily to an increase in volume sold of 1.9 million gallons, compared to a volume sold of 3.2 million gallons during the three months ended June 30, 2012. This increase was due primarily to the May 1, 2012 acquisition of Downeast. The increase in revenue resulting from higher volumes was partially offset by a decrease in the average selling price of $0.12 per gallon, as compared to an average selling price of $3.62 per gallon during the three months ended June 30, 2012.

Cost of Sales. Propane cost of sales for the three months ended June 30, 2013 increased approximately $2.0 million as compared to propane cost of sales of $23.2 million during the three months ended June 30, 2012. This increase was due primarily to an increase in volume sold of 4.1 million gallons compared to a volume sold of 19.3 million gallons during the three months ended June 30, 2012, as described above. The increase in cost of sales resulting from higher volumes was partially offset by a decrease in the average cost of $0.12 per gallon, as compared to an average cost of $1.20 during the three months ended June 30, 2012.

Distillate cost of sales for the three months ended June 30, 2013 increased approximately $3.6 million as compared to distillate cost of sales of $11.6 million during the three months ended June 30, 2012, due primarily to an increase in volume sold of 1.9 million gallons, compared to a volume sold of 3.2 million gallons during the three months ended June 30, 2012, as described above. The increase in cost of sales resulting from higher volumes was partially offset by a decrease in cost of sales resulting from a decrease in the average cost of $0.59 per gallon, as compared to an average cost of $3.58 per gallon during the three months ended June 30, 2012. Distillate cost of sales during the three months ended June 30, 2012 were increased by $1.0 million of unrealized losses on derivatives.

Operating Expenses. Operating expenses of our retail propane segment increased approximately $2.4 million during the three months ended June 30, 2013 as compared to operating expenses of $18.4 million during the three months ended June 30, 2012. This increase was due primarily to the acquisition of Downeast in May 2012.

General and Administrative Expenses. General and administrative expenses of our retail propane segment decreased approximately $0.1 million during the three months ended June 30, 2013 as compared to general and administrative expenses of $2.8 million during the three months ended June 30, 2012.

Depreciation and Amortization. Depreciation and amortization expense of our retail propane segment increased approximately $0.5 million during the three months ended June 30, 2013 as compared to depreciation and amortization expense of $6.7 million during the three months ended June 30, 2012.

Operating Loss. Our retail propane segment had an operating loss of approximately $1.5 million during the three months ended June 30, 2013 compared to an operating loss of $6.2 million during the three months ended June 30, 2012. The lower operating loss during the three months ended June 30, 2013 was due to increased sales volumes and higher product margins, partially offset by higher operating and general and administrative expenses.

Liquidity, Sources of Capital and Capital Resource Activities

Our principal sources of liquidity and capital are the cash flows from our operations and borrowings under our Revolving Credit Facility. Our cash flows from operations are discussed below.

Our borrowing needs vary significantly during the year due to the seasonal nature of our business. Our greatest working capital borrowing needs generally occur during the period of June through December, when we are building our natural gas liquids inventories in anticipation of the heating season. Our working capital borrowing needs generally decline during the period of January through March, when the cash flows from our retail propane and natural gas liquids logistics operations are the greatest.

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Under our partnership agreement, we are required to make distributions in an amount equal to all of our available cash, if any, no more than 45 days after the end of each fiscal quarter to holders of record on the applicable record dates. Available cash generally means all cash on hand at the end of the respective fiscal quarter less the amount of cash reserves established by our general partner in its reasonable discretion for future cash requirements. These reserves are retained for the proper conduct of our business, debt principal and interest payments and for distributions to our unitholders during the next four quarters. Our general partner reviews the level of available cash on a quarterly basis based upon information provided by management.

We believe that our anticipated cash flows from operations and the borrowing capacity under our Credit Agreement (as defined below) will be sufficient to meet our liquidity needs for the next 12 months. If our plans or assumptions change or are inaccurate, or if we make acquisitions, we may need to raise additional capital. Our ability to raise additional capital, if necessary, depends on various factors and conditions, including market conditions. We cannot give any assurances that we can raise additional capital to meet these needs. Commitments or expenditures, if any, we may make toward any acquisition projects are at our discretion.

We continue to pursue a strategy of growth through acquisitions. We expect to consider financing future acquisitions through a variety of sources, including the use of available capacity on our revolving credit facility, the issuance of equity to sellers of the businesses we acquire, private placements of common units or debt securities, and public offerings of common units or debt securities. Our ability to raise additional capital through the issuance of debt or equity securities will have a significant impact on our ability to continue to pursue our growth strategy.

Long-Term Debt

On June 19, 2012, we entered into a credit agreement (the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility”, and together with the Working Capital Facility, the “Revolving Credit Facility”). Also on June 19, 2012, we entered into a note purchase agreement (the “Note Purchase Agreement”) whereby we issued $250 million of Senior Notes in a private placement (the “Senior Notes”).

Credit Agreement

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	Amount		Rate
Expansion Capital Facility — LIBOR borrowings	$	444,500	3.20	%
Working Capital Facility — LIBOR borrowings	48,500		3.20	%
Base rate borrowings	27,500		5.25	%

At June 30, 2013, we were in compliance with all covenants under the Credit Agreement.

Senior Notes

At June 30, 2013, we were in compliance with all covenants under the Note Purchase Agreement and the Senior Notes.

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Previous Credit Facilities

Revolving Credit Balances

The following table provides certain information on revolving credit facility borrowings during the three months ended June 30, 2013 and 2012 (dollars in thousands):

	Daily Average		Lowest		Highest
	Balance		Balance		Balance
	During Quarter		During Quarter		During Quarter
Three Months Ended June 30, 2013:
Expansion loans	$	442,522	$	441,500	$	444,500
Working capital loans	26,967		—		76,000

Three Months Ended June 30, 2012:
New credit facility (June 19 - June 30) —
Expansion loans	$	254,000	$	254,000	$	254,000
Working capital loans	81,292		70,000		88,500
Previous credit facility (April 1 — June 19) —
Acquisition loans	222,238		186,000		239,275
Working capital loans	42,700		22,000		67,500

Cash Flows

The following summarizes the sources (uses) of our cash flows for the periods indicated (in thousands):

	Three Months Ended June 30,
	2013			2012
Cash Flows Provided by (Used In):

Operating activities, before changes in operating assets and liabilities	$	22,446		$	(12,879	)
Changes in operating assets and liabilities	3,490			(42,030		)

Operating activities	$	25,936		$	(54,909	)

Investing activities	(45,520		)	(281,938		)

Financing activities	12,626			350,482

Operating Activities. The seasonality of our natural gas liquids businesses has a significant effect on our cash flows from operating activities. The changes in our operating assets and liabilities caused by the seasonality of our retail and wholesale natural gas liquids businesses also have a significant impact on our net cash flows from operating activities. Increases in natural gas liquids prices will tend to result in reduced operating cash flows due to the need to use more cash to fund increases in inventories, and price decreases tend to increase our operating cash flow due to lower cash requirements to fund increases in inventories.

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In general, our operating cash flows are at their lowest levels during our first and second fiscal quarters, or the six months ending September 30, when we experience operating losses or less operating income as a result of lower volumes of natural gas liquids sales and when we are building our inventory levels for the upcoming heating season. Our operating cash flows are generally greatest during our third and fourth fiscal quarters, or the six months ending March 31, when our operating income levels are highest and customers pay for natural gas liquids consumed during the heating season months. We will borrow under our Revolving Credit Facility to supplement our operating cash flows as necessary during our first and second quarters.

We acquired a crude oil logistics business and a water services business near the end of the quarter ended June 30, 2012, through our merger with High Sierra. These businesses are less subject to seasonal fluctuations, and these businesses contributed significantly to our cash flows from operations during the three months ended June 30, 2013.

Investing Activities. Our cash flows from investing activities are primarily impacted by our capital expenditures. In periods where we are engaged in significant acquisitions, we will generally realize negative cash flows in investing activities, which, depending on our cash flows from operating activities, may require us to increase the borrowings under our Revolving Credit Facility.

During the three months ended June 30, 2013, we paid $30.2 million for capital expenditures, which related primarily to water disposal and natural gas liquids terminal assets. Of this amount, approximately $23.9 million represented expansion capital and approximately $6.3 million represented maintenance capital. We also paid $5.4 million to acquire two retail propane businesses.

During the three months ended June 30, 2012, we completed our merger with High Sierra, for which we paid $239.3 million, net of cash acquired, and issued 20,703,510 common units. Also, during the three months ended June 30, 2012, we completed three acquisitions of retail propane and distillate businesses, for which we paid $56.1 million and issued 750,000 common units.

Financing Activities. Changes in our cash flow from financing activities include advances from and repayments on our revolving credit facilities, either to fund our operating or investing requirements. In periods where our cash flows from operating activities are reduced (such as during our first and second quarters), we may fund the cash flow deficits through our working capital facility. During the three months ended June 30, 2013, we borrowed $43.0 million on our revolving credit facility (net of repayments). During the three months ended June 30, 2012, we borrowed $128.5 million on our revolving credit facilities (net of repayments) and issued $250.0 million of Senior Notes. During the three months ended June 30, 2012, we paid $18.5 million of debt issuance costs.

Cash flows from financing activities also include distributions paid to owners. We expect our distributions to our partners to increase in future periods under the terms of our partnership agreement. Based on the number of common and subordinated units outstanding at June 30, 2013 (exclusive of invested restricted units issued pursuant to employee and director compensation programs), if we made distributions equal to our minimum quarterly distribution of $0.3375 per unit ($1.35 annualized), total distributions would equal $18.1 million per quarter ($72.5 million per year). To the extent our cash flows from operating activities are not sufficient to finance our required distributions, we may be required to increase the borrowings under our Working Capital Facility.

The following table summarizes the distributions declared since our initial public offering:

			Amount		Amount Paid to		Amount Paid to
Date Declared	Record Date	Date Paid	Per Unit		Limited Partners		General Partner
					(in thousands)		(in thousands)
July 25, 2011	August 3, 2011	August 12, 2011	$	0.1669	$	2,467	$	3
October 21, 2011	October 31, 2011	November 14, 2011	0.3375		4,990		5
January 24, 2012	February 3, 2012	February 14, 2012	0.3500		7,735		10
April 18, 2012	April 30, 2012	May 15, 2012	0.3625		9,165		10
July 24, 2012	August 3, 2012	August 14, 2012	0.4125		13,574		134
October 17, 2012	October 29, 2012	November 14, 2012	0.4500		22,846		707
January 24, 2013	February 4, 2013	February 14, 2013	0.4625		24,245		927
April 25, 2013	May 6, 2013	May 15, 2013	0.4775		25,605		1,189
July 25, 2013	August 5, 2013	August 14, 2013	0.4938		31,725		1,739

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Contractual Obligations

The following table updates our contractual obligations summary as of June 30, 2013 for our fiscal years ending thereafter (amounts in thousands):

			For the
			Nine Months
			Ending
			March 31,		For the Years Ending March 31,						After March 31,
	Total		2014		2015		2016		2017		2017
	(in thousands)
Principal payments on long-term debt —
Expansion capital borrowings	$	444,500	$	—	$	—	$	—	$	—	$	444,500
Working capital borrowings	76,000		—		—		—		—		76,000
Senior notes	250,000		—		—		—		—		250,000
Other long-term debt	20,036		6,302		6,735		3,386		2,108		1,505
Interest payments on long-term debt —
Revolving Credit Facility (1)	83,947		15,874		21,146		21,146		21,146		4,635
Senior Notes	112,219		12,469		16,625		16,625		16,625		49,875
Other long-term debt	1,297		323		411		257		163		143
Standby letters of credit	73,898		—		—		—		—		73,898
Future minimum lease payments under noncancelable operating leases	202,243		43,468		37,493		31,376		29,035		60,871
Fixed price commodity purchase commitments	74,513		74,513		—		—		—		—
Index priced commodity purchase commitments (2)	1,250,762		1,168,175		54,829		27,758		—		—
Total contractual obligations	$	2,589,415	$	1,321,124	$	137,239	$	100,548	$	69,077	$	961,427

Natural gas liquids gallons under fixed-price purchase commitments (thousands) (3)	82,653		82,653		—		—		—		—
Natural gas liquids gallons under index-price purchase commitments (thousands) (3)	805,884		786,185		19,699		—		—		—
Crude oil barrels under index-price purchase commitments (thousands) (3)	5,439		4,607		475		357		—		—

(1) The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at June 30, 2013. See Note 7 to our consolidated financial statements included elsewhere herein for additional information on our Credit Agreement.

(2) Index prices are based on a forward price curve as of June 30, 2013. A theoretical change of $0.10 per gallon in the underlying commodity price at June 30, 2013 would result in a change of approximately $80.6 million in the value of our index-based natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel in the underlying commodity price at June 30, 2013 would result in a change of approximately $5.4 million in the value of our index-based crude oil purchase commitments.

(3) At June 30, 2013, we had fixed priced and index priced sales contracts for approximately 139.3 million and 533.9 million gallons of natural gas liquids, respectively. At June 30, 2013, we had index-price sales contracts for approximately 5.3 million barrels of crude oil.

Off-Balance Sheet Arrangements

We do not have any off balance sheet arrangements other than the operating leases described in Note 9 to the financial statements included elsewhere in this interim report.

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Environmental Legislation

Please see our Annual Report on Form 10-K for the year ended March 31, 2013 for a discussion of proposed environmental legislation and regulations that, if enacted, could result in increased compliance and operating costs. However, at this time we cannot predict the structure or outcome of any future legislation or regulations or the eventual cost we could incur in compliance.

Trends

Crude Oil Logistics

Crude oil prices fluctuate widely, due to changes in supply and demand conditions. The opportunity to generate revenues in our crude oil logistics business is heavily influenced by the volume of crude oil being produced. Currently, production of crude oil in North America is high. Changes in the level of production could impact our ability to generate revenues in the future.

In addition, the spread between the prices of crude in different locations can also fluctuate widely. If these price differences are high, we are able to generate higher margins by transporting crude from lower-price markets to higher-price markets. During fiscal 2013, the spread between crude oil prices in the mid-continent region and crude oil prices in south Texas widened, which gave us the opportunity to generate favorable margins by transporting crude from one region to the other. This spread narrowed considerably during the three months ended June 30, 2013.

Water Services

Our opportunity to earn revenues in our water services business is based on the level of production of natural gas and crude oil in the areas where our facilities are located. Recently, production has been strong in these regions. A future decline in the level of production could have an adverse impact on profitability.

Our facility in Wyoming and two of our facilities in Colorado have the capability to process wastewater to the point where it can be returned to the producer for use in future drilling operations. We typically generate additional profits from this activity. Future changes in customer attitudes or in the regulatory climate could provide future opportunities for us to generate increased profits from these activities.

Natural Gas Liquids Logistics

The volumes we sell in our wholesale natural gas liquids business are heavily dependent on the demand for propane and butane, which is influenced by weather conditions. During the most recent winter weather conditions were relatively mild, and the preceding winter was one of the warmest on record, which reduced demand and resulted in lower prices for natural gas liquids. The margins we generate in our wholesale natural gas liquids business are influenced by changes in prices over the course of a year. During years when demand is higher during the winter months, we have the opportunity to utilize our storage assets to increase margins.

Retail Propane

The volumes we sell in our retail propane business are heavily dependent on weather conditions, as cold weather significantly increases customer demand for propane. During times of lower propane prices, such as we have experienced over the two most recent years, margins per gallon typically increase. During times of higher propane prices, such as we may experience in the future, margins per gallon typically decrease.

Critical Accounting Policies

The preparation of financial statements and related disclosures in compliance with GAAP requires the selection and application of appropriate accounting principles to the relevant facts and circumstances of the Partnership’s operations and the use of estimates made by management. We have identified the following critical accounting policies that are most important to the portrayal of our financial condition and results of operations. Changes in these policies could have a material effect on the financial statements.

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The application of these accounting policies necessarily requires our most subjective or complex judgments regarding estimates and projected outcomes of future events which could have a material impact on the financial statements.

Revenue Recognition

Impairment of Long-Lived Assets

Goodwill is subject to at least an annual assessment for impairment. We perform our annual assessment of impairment during the fourth quarter of our fiscal year, and more frequently if circumstances warrant. We completed the assessment of each of our reporting units and determined no impairment existed for the year ended March 31, 2013. The assessment of the value of our reporting units requires us to make certain assumptions relating to future operations. When evaluating operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge. To date, we have not recognized any impairment on assets we have acquired.

We evaluate property, plant and equipment and amortizable intangible assets for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is less than its carrying value. We did not record any impairments of long-lived assets during the three months ended June 30, 2013 or 2012.

Asset Retirement Obligations

We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value can be made. In order to determine the fair value of such a liability, we must make certain estimates and assumptions including, among other things, projected cash flows, the estimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time. At June 30, 2013, we have recorded a liability of $1.6 million for obligations related to the retirement of pipeline injection facilities of our crude oil logistics business and the facilities of our water services business.

In addition to the pipeline injection facilities and the water processing facilities, we may be obligated by contractual or regulatory requirements to remove certain of our other assets, or perform other remediation of the sites where such assets are located, upon the retirement of those assets. However, we do not believe the present value of such asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of our facilities, is material to our financial position or results of operations.

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment

Depreciation expense represents the systematic and rational write-off of the cost of our property and equipment, net of residual or salvage value (if any), to the results of operations for the quarterly and annual periods the assets are used. We depreciate the majority of our property and equipment using the straight-line method, which results in our recording depreciation expense evenly over the estimated life of the individual asset. The estimate of depreciation expense requires us to make assumptions regarding the useful economic lives and residual values of our assets. At the time we acquire and place our property and equipment in service, we develop assumptions about such lives and residual values that we believe are reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our depreciation expense amounts prospectively.

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Examples of such circumstances include changes in laws and regulations that limit the estimated economic life of an asset; changes in technology that render an asset obsolete; or changes in expected salvage values.

The net book value of our property, plant and equipment was $536.5 million at June 30, 2013. We recorded depreciation expense of $13.4 million and $6.1 million for the three months ended June 30, 2013 and 2012, respectively.

For additional information regarding our property and equipment, see Note 5 of our condensed consolidated financial statements included elsewhere in this Quarterly Report.

Business Combinations

We have made in the past, and expect to make in the future, acquisitions of other businesses. We record business combinations using a method known as the “acquisition method,” in which the assets acquired and liabilities assumed are recorded at their estimated fair values. Fair values of assets acquired and liabilities assumed are based upon available information and may involve us engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identify and include in the allocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property and equipment and intangible assets, including those with indefinite lives. The excess of purchase price over the net fair value of acquired assets over the assumed liabilities is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Generally, we have up to one year from the acquisition date to finalize the identification and valuation of acquired assets and liabilities. The impact of subsequent changes to the identification of assets and liabilities may require a retroactive adjustment to our previously reported financial position and results of operations.

Inventory

Our inventory consists primarily of propane, butane, and crude oil. The market value of these commodities changes on a daily basis as supply and demand conditions change. We value our inventory using the weighted-average cost and first-in first-out methods. At the end of each fiscal year, we also perform a “lower of cost or market” analysis; if the cost basis of the inventory would not be recoverable based on market prices at the end of the year, we reduce the book value of the inventory to the recoverable amount. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business to sell the inventory in retail markets. When performing this analysis during interim periods within a fiscal year, accounting standards do not require us to record a lower-of-cost-or market writedown if we expect the market values to recover by our fiscal year end of March 31. We are unable to control changes in the market value of these commodities and are unable to determine whether writedowns will be required in future periods. In addition, writedowns at interim periods could be required if we cannot conclude that market values will recover sufficiently by our fiscal year end.

Product Exchanges

In our natural gas liquids logistics business, we frequently have exchange transactions with suppliers or customers in which we will deliver product volumes to them, or receive product volumes from them to be delivered back to us or from us in future periods, generally in the short-term (referred to as “product exchanges”). The settlements of exchange volumes are generally done through in-kind arrangements whereby settlement volumes are delivered at no cost, with the exception of location or timing differentials. Such in-kind deliveries are ongoing and can take place over several months. We estimate the value of product exchange assets and liabilities based on the weighted-average cost basis of the inventory we have delivered or will deliver on the exchange, plus or minus location differentials, which we believe represents the value of the exchange volumes at such date. Changes in product prices could impact our estimates.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

As of June 30, 2013, a significant portion of our long-term debt is variable-rate debt. Changes in interest rates impact the interest payments of our variable-rate debt but generally do not impact the fair value of the liability. Conversely, changes in interest rates impact the fair value of the fixed-rate debt but do not impact its cash flows.

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. As of June 30, 2013, we had $520.5 million of outstanding borrowings under our revolving credit facility. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of approximately $0.7 million.

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Commodity Price and Credit Risk

Our operations are subject to certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that the market value of crude oil, propane, and other natural gas liquids will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract.

As is customary in the crude oil industry, we generally receive payment from customers for sale of crude oil on a monthly basis. As a result, receivables from individual customers in our crude business are generally higher than the receivables from customers in our other segments.

We take an active role in managing and controlling commodity price and credit risks and have established control procedures, which we review on an ongoing basis. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, restrictions on product liftings, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions, as deemed appropriate. The principal counterparties associated with our operations as of June 30, 2013 were retailers, resellers, energy marketers, producers, refiners and dealers.

The natural gas liquids and crude oil industries are “margin-based” and “cost-plus” businesses in which gross profits depend on the differential of sales prices over supply costs. As a result, our profitability will be impacted by changes in wholesale prices of natural gas liquids and crude oil. When there are sudden and sharp increases in the wholesale cost of natural gas liquids and crude oil, we may not be able to pass on these increases to our customers through retail or wholesale prices. Natural gas liquids and crude oil are commodities and the price we pay for them can fluctuate significantly in response to supply or other market conditions. We have no control over supply or market conditions. In addition, the timing of cost increases can significantly affect our realized margins. Sudden and extended wholesale price increases could reduce our gross margins and could, if continued over an extended period of time, reduce demand by encouraging end users to conserve or convert to alternative energy sources.

We engage in derivative financial and other risk management transactions, including various types of forward contracts, options, swaps and future contracts, to reduce the effect of price volatility on our product costs, protect the value of our inventory positions and to help ensure the availability of product during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes when we have a matching purchase commitment from our wholesale and retail customers. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio.

Although we use derivative commodity instruments to reduce the market price risk associated with forecasted transactions, we have not accounted for such derivative commodity instruments as hedges. In addition, we do not use such derivative commodity instruments for speculative or trading purposes. As of June 30, 2013, the fair value of our unsettled commodity derivative instruments was a net liability of $3.3 million. We record the changes in fair value of these derivative commodity instruments within cost of sales. The following table summarizes the hypothetical impact on the fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands):

	Increase
	(Decrease)
	To Fair Value
Crude oil (crude oil logistics segment)	$	(5,404	)
Crude oil (water services segment)	(1,114		)
Crude oil (natural gas liquids logistics segment)	(9,165		)
Propane (natural gas liquids logistics segment)	(1,381		)
Other natural gas liquids (natural gas liquids logistics segment)	(5,940		)
Heating oil (retail segment)	8

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Fair Value

We use observable market values for determining the fair value of our derivative instruments. In cases where actively quoted prices are not available, other external sources are used which incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis.

Item 4. Controls and Procedures

We maintain disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) of the Securities Exchange Act of 1934) that are designed to provide reasonable assurance that information required to be disclosed in our filings and submissions under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

We completed an evaluation under the supervision and with participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of June 30, 2013. Based on this evaluation, our principal executive officer and principal financial officer have concluded that as of June 30, 2013, such disclosure controls and procedures were effective to provide the reasonable assurance described above.

Other than changes that have resulted or may result from our business combinations during the year ended March 31, 2013, as discussed below, there have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)—15(f) of the Exchange Act) during the three months ended June 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

We closed several business combinations during the year ended March 31, 2013, as described in Note 1 to our consolidated financial statements included in this Quarterly Report on Form 10-Q. At this time, we continue to evaluate the business and internal controls and processes of these acquired businesses and are making various changes to their operating and organizational structure based on our business plan. We are in the process of implementing our internal control structure over these acquired businesses. We expect that our evaluation and integration efforts related to those combined operations will continue into future quarters in fiscal 2014, due to the magnitude of those businesses.

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PART II

Item 1. Legal Proceedings

For information related to legal proceedings, please see the discussion under the captions “Legal matters” and “Customer Dispute” in Note 9 to our unaudited condensed consolidated financial statements in Part I, Item I of this Quarterly Report on Form 10-Q, which information is incorporated by reference into this Item 1.

Item 1A. Risk Factors

There have been no material changes from the risk factors previously disclosed in “Item 1A — Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended March 31, 2013.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit Number				Exhibit

4	.	1		Amendment No. 2 to Note Purchase Agreement, dated as of May 8, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 9, 2013).
10	.	1		Amendment No. 2 to Credit Agreement, dated as of May 8, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 9, 2013).
12	.	1	*	Ratio of earnings to fixed charges
31	.	1	*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002
31	.	2	*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002
32	.	1	*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002
32	.	2	*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002
101	.	INS	**	XBRL Instance Document
101	.	SCH	**	XBRL Schema Document
101	.	CAL	**	XBRL Calculation Linkbase Document
101	.	DEF	**	XBRL Definition Linkbase Document
101	.	LAB	**	XBRL Label Linkbase Document
101	.	PRE	**	XBRL Presentation Linkbase Document

			*	Exhibits filed with this report.
			**	Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of June 30, 2013 and March 31, 2013, (ii) Condensed Consolidated Statement of Operations for the three months ended June 30, 2013 and 2012, (iii) Condensed Consolidated Statements of Comprehensive Loss for the three months ended June 30, 2013 and 2012, (iv) Condensed Consolidated Statement of Changes in Partners’ Equity for the three months ended June 30, 2013, (v) Condensed Consolidated Statement of Cash Flows for the three months ended June 30, 2013 and 2012, and (vi) Notes to Condensed Consolidated Financial Statements.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	NGL ENERGY PARTNERS LP

	By:	NGL Energy Holdings LLC, its general partner

Date: August 9, 2013		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer


Date: August 9, 2013		By:	/s/ Atanas H. Atanasov
			Atanas H. Atanasov
			Chief Financial Officer

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EXHIBIT INDEX

Exhibit Number			Exhibit

4.	1		Amendment No. 2 to Note Purchase Agreement, dated as of May 8, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 9, 2013).
10.	1		Amendment No. 2 to Credit Agreement, dated as of May 8, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 9, 2013).
12.	1	*	Ratio of earnings to fixed charges
31.	1	*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002
31.	2	*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002
32.	1	*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002
32.	2	*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002
101.	INS	**	XBRL Instance Document
101.	SCH	**	XBRL Schema Document
101.	CAL	**	XBRL Calculation Linkbase Document
101.	DEF	**	XBRL Definition Linkbase Document
101.	LAB	**	XBRL Label Linkbase Document
101.	PRE	**	XBRL Presentation Linkbase Document

			*	Exhibits filed with this report.
			**	Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of June 30, 2013 and March 31, 2013, (ii) Condensed Consolidated Statement of Operations for the three months ended June 30, 2013 and 2012, (iii) Condensed Consolidated Statements of Comprehensive Loss for the three months ended June 30, 2013 and 2012, (iv) Condensed Consolidated Statement of Changes in Partners’ Equity for the three months ended June 30, 2013, (v) Condensed Consolidated Statement of Cash Flows for the three months ended June 30, 2013 and 2012, and (vi) Notes to Condensed Consolidated Financial Statements.