NGL Energy Partners LP - Quarter Report: 2013 September (Form 10-Q)

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 September 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 November 5, 2013, there were 66,650,735 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 September 30, 2013 and March 31, 2013	3
	Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2013 and 2012	4
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and six months ended September 30, 2013 and 2012	5
	Condensed Consolidated Statement of Changes in Partners’ Equity for the six months ended September 30, 2013	6
	Condensed Consolidated Statements of Cash Flows for the six months ended September 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	38
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	69
Item 4.	Controls and Procedures	70

PART II

Item 1.	Legal Proceedings	71
Item 1A.	Risk Factors	71
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	71
Item 3.	Defaults Upon Senior Securities	71
Item 4.	Mine Safety Disclosures	71
Item 5.	Other Information	71
Item 6.	Exhibits	72

Signatures		74

Exhibit Index		75

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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;

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· loss of key personnel;

· 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 non-payment 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 September 30, 2013 and March 31, 2013

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

	September 30,			March 31,
	2013			2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	5,528		$	11,561
Accounts receivable - trade, net of allowance for doubtful accounts of $1,893 and $1,760, respectively	602,033			562,889
Accounts receivable - affiliates	3,071			22,883
Inventories	355,300			126,895
Prepaid expenses and other current assets	47,927			37,891
Total current assets	1,013,859			762,119

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $76,390 and $50,127, respectively	631,663			516,937
GOODWILL	840,287			563,146
INTANGIBLE ASSETS, net of accumulated amortization of $68,790 and $44,155, respectively	534,746			442,603
OTHER NONCURRENT ASSETS	5,938			6,542
Total assets	$	3,026,493		$	2,291,347

LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES:
Trade accounts payable	$	604,018		$	535,687
Accrued expenses and other payables	101,988			85,703
Advance payments received from customers	67,994			22,372
Accounts payable - affiliates	18,429			6,900
Current maturities of long-term debt	8,229			8,626
Total current liabilities	800,658			659,288

LONG-TERM DEBT, net of current maturities	906,066			740,436
OTHER NONCURRENT LIABILITIES	2,673			2,205

COMMITMENTS AND CONTINGENCIES

PARTNERS’ EQUITY, per accompanying statement:
General Partner — 0.1% interest; 71,288 and 53,676 notional units outstanding at September 30, 2013 and March 31, 2013, respectively	(48,782		)	(50,497		)
Limited Partners — 99.9% interest — Common units — 65,296,884 and 47,703,313 units outstanding at September 30, 2013 and March 31, 2013, respectively	1,354,305			920,998
Subordinated units — 5,919,346 units outstanding at September 30, 2013 and March 31, 2013	4,130			13,153
Accumulated other comprehensive income (loss) — Foreign currency translation	(6		)	24
Noncontrolling interests	7,449			5,740
Total partners’ equity	1,317,096			889,418
Total liabilities and partners’ equity	$	3,026,493		$	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 and Six Months Ended September 30, 2013 and 2012

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

	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
REVENUES:
Crude oil logistics	$	1,014,008		$	711,021		$	1,944,802		$	784,538
Water services	34,190			15,810			54,703			17,751
Natural gas liquids logistics	484,874			350,368			845,833			541,985
Retail propane	59,380			57,003			131,597			116,211
Other	1,485			1,308			2,959			1,461
Total Revenues	1,593,937			1,135,510			2,979,894			1,461,946

COST OF SALES:
Crude oil logistics	992,135			693,687			1,901,354			770,570
Water services	3,782			2,054			4,365			2,670
Natural gas liquids logistics	459,394			328,283			809,645			512,328
Retail propane	33,539			29,666			76,562			67,107
Total Cost of Sales	1,488,850			1,053,690			2,791,926			1,352,675

OPERATING COSTS AND EXPENSES:
Operating	55,769			39,431			104,814			62,769
General and administrative	14,312			10,443			32,766			20,403
Depreciation and amortization	25,061			13,361			47,785			22,588
Operating Income	9,945			18,585			2,603			3,511

OTHER INCOME (EXPENSE):
Interest expense	(11,060		)	(8,692		)	(21,682		)	(12,492		)
Loss on early extinguishment of debt	—			—			—			(5,769		)
Interest income	266			263			664			629
Other, net	153			3			(195		)	29
Income (Loss) Before Income Taxes	(696		)	10,159			(18,610		)	(14,092		)

INCOME TAX (PROVISION) BENEFIT	(236		)	(77		)	170			(536		)

Net Income (Loss)	(932		)	10,082			(18,440		)	(14,628		)

Net Income Allocated to General Partner	(2,451		)	(694		)	(4,139		)	(789		)

Net (Income) Loss Attributable to Noncontrolling Interests	(9		)	(9		)	(134		)	51

Net Income (Loss) Attributable to Parent Equity Allocated to Limited Partners	$	(3,392	)	$	9,379		$	(22,713	)	$	(15,366	)

Basic and Diluted Income (Loss) per Common Unit	$	(0.05	)	$	0.18		$	(0.37	)	$	(0.37	)

Basic and Diluted Income (Loss) per Subordinated Unit	$	(0.09	)	$	0.18		$	(0.52	)	$	(0.38	)

Basic and Diluted Weighted Average Units Outstanding:
Common	58,909,389			44,831,836			53,336,969			35,730,492
Subordinated	5,919,346			5,919,346			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 Income (Loss)

Three Months and Six Months Ended September 30, 2013 and 2012

(U.S. Dollars in Thousands)

	Three Months Ended					Six Months Ended
	September 30,					September 30,
	2013			2012		2013			2012

Net income (loss)	$	(932	)	$	10,082	$	(18,440	)	$	(14,628	)
Other comprehensive income (loss), net of tax:
Change in foreign currency translation adjustment	(5		)	10		(30		)	(3		)
Comprehensive income (loss)	$	(937	)	$	10,092	$	(18,470	)	$	(14,631	)

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

Six Months Ended September 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	(2,928		)	—	(51,581		)	—	(5,749		)	—			(365		)	(60,623		)
Contributions	504			—	—			—	—			—			1,940			2,444
Sales of units in public offerings, net of issuance costs	—			14,450,000	415,089			—	—			—			—			415,089
Units issued in business combinations, net of offering costs	—			2,860,879	80,619			—	—			—			—			80,619
Equity issued pursuant to incentive compensation plan	—			282,692	8,619			—	—			—			—			8,619
Net income (loss)	4,139			—	(19,439		)	—	(3,274		)	—			134			(18,440		)
Foreign currency translation adjustment	—			—	—			—	—			(30		)	—			(30		)
BALANCES, SEPTEMBER 30, 2013	$	(48,782	)	65,296,884	$	1,354,305		5,919,346	$	4,130		$	(6	)	$	7,449		$	1,317,096

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

Six Months Ended September 30, 2013 and 2012

(U.S. Dollars in Thousands)

	Six Months Ended
	September 30,
	2013			2012
OPERATING ACTIVITIES:
Net loss	$	(18,440	)	$	(14,628	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization, including debt issuance cost amortization	51,821			25,476
Loss on early extinguishment of debt	—			5,769
Non-cash equity-based compensation expense	6,762			2,957
Loss (gain) on disposal of assets	2,163			(23		)
Provision for doubtful accounts	781			356
Commodity derivative (gain) loss	17,881			(5,019		)
Other	8			72
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable - trade	(27,881		)	101,739
Accounts receivable - affiliates	19,812			6,768
Inventories	(226,727		)	(121,981		)
Prepaid expenses and other current assets	(10,830		)	3,793
Trade accounts payable	61,093			(77,965		)
Accrued expenses and other payables	18,065			(15,664		)
Accounts payable - affiliates	11,529			(6,698		)
Advance payments received from customers	45,622			42,242
Net cash used in operating activities	(48,341		)	(52,806		)

INVESTING ACTIVITIES:
Purchases of long-lived assets	(67,399		)	(14,595		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	(393,008		)	(307,082		)
Cash flows from commodity derivatives	(19,074		)	10,692
Proceeds from sales of assets	2,224			581
Other	—			427
Net cash used in investing activities	(477,257		)	(309,977		)

FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	1,061,500			594,675
Payments on revolving credit facilities	(893,000		)	(422,675		)
Issuance of senior notes	—			250,000
Proceeds from borrowings on other long-term debt	880			—
Payments on other long-term debt	(4,507		)	(251		)
Debt issuance costs	(2,218		)	(17,839		)
Contributions	2,444			751
Distributions	(60,623		)	(22,883		)
Proceeds from sale of common units, net of offering costs	415,089			(818		)
Net cash provided by financing activities	519,565			380,960
Net increase (decrease) in cash and cash equivalents	(6,033		)	18,177
Cash and cash equivalents, beginning of period	11,561			7,832
Cash and cash equivalents, end of period	$	5,528		$	26,009

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 September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 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:

· During October 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.

· During November 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.

· During January 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.

· During February 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 six months ended September 30, 2013, we completed three acquisitions of retail propane and distillate businesses.

· On July 1, 2013, we completed a business combination whereby we acquired the assets of Crescent Terminals, LLC and the ownership interests in Cierra Marine, LP and its affiliated companies (collectively, “Crescent”), whereby we acquired four tow boats, seven crude oil barges, and one crude oil terminal in South Texas.

· On July 2, 2013, we completed a business combination with High Roller Wells Big Lake SWD No. 1, Ltd. (“Big Lake”), whereby we acquired one water disposal facility in West Texas. We also entered into a development agreement that provides us the option to purchase disposal facilities that may be developed in the future.

· On August 2, 2013, we completed a business combination whereby we acquired seven entities affiliated with Oilfield Water Lines LP (collectively, “OWL”). The businesses of OWL include water disposal operations and a water transportation business in Texas.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

· On September 1, 2013, we completed a business combination whereby we acquired a crude oil marketing business in Oklahoma and Texas.

· On September 3, 2013, we completed a business combination with Coastal Plains Disposal #1, LLC (“Coastal”), in which we acquired the ownership interests in a water disposal facility in Texas.

As of September 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.

· 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.

· 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 and six months ended September 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. We have made certain reclassifications to the prior period financial statements to conform with classification methods used in the current fiscal year. These reclassifications had no impact on previously-reported amounts of total assets, liabilities, partners’ equity, or net income.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States 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 September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 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 September 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 September 30, 2013 or March 31, 2013.

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

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

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				Six Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
	(in thousands)				(in thousands)

Interest paid, exclusive of debt issuance costs	$	8,423	$	6,594	$	16,908	$	9,831
Income taxes paid	$	369	$	—	$	650	$	176

Value of common units issued in business combinations	$	80,619	$	2,224	$	80,619	$	433,668

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:

	September 30,		March 31,
	2013		2013
	(in thousands)
Crude oil	$	56,514	$	46,156
Propane	207,511		45,428
Butane	62,852		23,106
Other natural gas liquids	14,947		984
Other	13,476		11,221
	$	355,300	$	126,895

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following:

	September 30,		March 31,
	2013		2013
	(in thousands)

Product exchange liabilities	$	42,232	$	6,741
Income and other tax liabilities	22,230		22,659
Accrued compensation and benefits	14,885		27,252
Other	22,641		29,051
	$	101,988	$	85,703

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

Business Combination Measurement Period

We record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Pursuant to GAAP, an entity is allowed a reasonable period of time to obtain the information necessary to identify and measure the value of the assets acquired and liabilities assumed in a business combination. As described in Note 3, certain of our acquisitions during the fiscal year ended March 31, 2013 and during the six months ended September 30, 2013 are still within this measurement period, and as a result, the acquisition date values we have recorded for the acquired assets and assumed liabilities are subject to change.

Also as described in Note 3, we made certain adjustments during the six months ended September 30, 2013 to our estimates of the acquisition date fair values of assets acquired and liabilities assumed in certain business combinations that occurred during the fiscal year ended March 31, 2013. Due to the immateriality of these adjustments, we did not retroactively adjust the consolidated balance sheet at March 31, 2013 or the consolidated statements of operations for periods during the year ended March 31, 2013 for these measurement period adjustments.

Note 3 — Acquisitions

Fiscal Year Ending March 31, 2014

Oilfield Water Lines, LP

On August 2, 2013, we completed a business combination with OWL, whereby we acquired water disposal and transportation assets in Texas. We issued 2,463,287 common units, valued at $68.6 million, and paid $167.7 million of cash, net of cash acquired, in exchange for OWL. The acquisition agreements also contemplate a post-closing payment for certain working capital items. The acquisition agreements also include a provision whereby the purchase price may be increased if certain performance targets are achieved. If the acquired assets generate Adjusted EBITDA, as defined in the acquisition agreements, in excess of $3.3 million during any one of the six months following the acquisition, the purchase price will be increased by seventy-two times the amount by which this target is exceeded. The maximum potential increase to the purchase price under this provision is $60 million. We incurred and charged to general and administrative expense during the six months ended September 30, 2013 approximately $0.7 million of costs related to the OWL acquisition.

We are in the process of identifying and determining the fair value of the assets and liabilities acquired in the acquisition of OWL. The estimates of fair value reflected as of September 30, 2013 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	8,550
Inventories	154
Other current assets	382
Property, plant and equipment:
Land	710
Water treatment facilities and equipment (3-30 years)	24,495
Vehicles (5-10 years)	8,254
Buildings and leasehold improvements (7-30 years)	740
Other (3-5 years)	264
Intangible assets:
Customer relationships (10 years)	56,000
Goodwill	145,558
Trade accounts payable	(6,063		)
Accrued expenses	(2,691		)
Other noncurrent liabilities	(64		)
Fair value of net assets acquired	$	236,289

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	167,720
Value of common units issued	68,569
Total consideration paid	$	236,289

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

As described above, the agreements with the former owners of OWL contain a provision whereby the purchase price may be increased if the business meets a specified performance target during the six months subsequent to the acquisition. In order to determine an estimate of the fair value of this contingent consideration at the acquisition date, we identified the variables most likely to impact this performance target. Using historical and projected data, we prepared a Monte-Carlo type simulation and applied an option pricing model. We concluded that the fair value of the contingent consideration approximated zero, and as a result, we did not record a liability at the acquisition date for the contingent consideration. We performed a similar calculation at September 30, 2013, and concluded that the fair value of the contingent consideration continued to approximate zero at September 30, 2013. We will evaluate the fair value of the contingent consideration again at December 31, 2013, and if we conclude that the contingent consideration has a fair value at that date, we will record a liability and a corresponding expense during the three months ending December 31, 2013.

The operations of OWL have been included in our consolidated statement of operations since OWL was acquired on August 2, 2013. Our consolidated statements of operations for the three months and six months ended September 30, 2013 include revenues of $7.3 million and operating income of $0.5 million that was generated by the operations of OWL. The following unaudited pro forma consolidated data below is presented for the six months ended September 30, 2013 as if the OWL acquisition had been completed on April 1, 2013 (in thousands, except per unit amounts). The pro forma earnings per unit are based on the common and subordinated units outstanding as of September 30, 2013.

Revenues	$	2,991,936
Net loss	(17,482		)
Limited partners’ interest in net loss	(21,755		)
Basic and diluted loss per common unit	(0.31		)
Basic and diluted loss per subordinated unit	(0.31		)

The pro forma consolidated data in the table above was prepared by adding the historical results of operations of OWL to our historical results of operations and making certain pro forma adjustments. The pro forma adjustments include: (i) replacing the historical depreciation and amortization expense of OWL with pro forma depreciation and amortization expense, calculated using the estimated fair values of long-lived assets recorded in the acquisition accounting; (ii) replacing the historical interest expense of OWL with pro forma interest expense; and (iii) excluding professional fees and other expenses incurred by us that were directly related to the acquisition. In order to calculate pro forma earnings per unit in the table above, we assumed that: (i) the same number of limited partner units outstanding at September 30, 2013 had been outstanding throughout the period shown in the table, and (ii) all of the common units were eligible for distributions related to the period shown in the table. The pro forma information is not necessarily indicative of the results of operations that would have occurred if the acquisition had been completed on April 1, 2013, nor is it necessarily indicative of the future results of the combined operations. We have not presented pro forma data for periods during the prior fiscal year, as certain of the assets we acquired in the acquisition of OWL had not yet been developed as of September 30, 2012.

Other Water Services Acquisitions

During the three months ended September 30, 2013, we completed two separate acquisitions of businesses to expand our water services operations in Texas. On a combined basis, we issued 222,381 common units, valued at $6.8 million, and paid $151.5 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. The agreements for the

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

acquisitions of these businesses contemplate post-closing payments for certain working capital items. We incurred and charged to general and administrative expense during the six months ended September 30, 2013 approximately $0.3 million of costs related to these acquisitions.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these two business combinations. The estimates of fair value reflected as of September 30, 2013 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	1,959
Inventories	192
Other current assets	112
Property, plant and equipment:
Land	206
Vehicles (5-10 years)	90
Water treatment facilities and equipment (3-30 years)	15,683
Buildings and leasehold improvements (7-30 years)	616
Other (3-5 years)	12
Intangible assets:
Customer relationships (5-10 years)	36,500
Trade names (indefinite life)	2,800
Non-compete agreements (3 years)	260
Development agreement (5 years)	14,000
Option agreement	2,500
Goodwill	83,813
Trade accounts payable	(82		)
Accrued expenses	(273		)
Other noncurrent liabilities	(64		)
Fair value of net assets acquired	$	158,324

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	151,530
Value of common units issued	6,794
Total consideration paid	$	158,324

As part of one of these business combinations, we entered into a development agreement with the seller of the business. Under this agreement, we have the option to purchase water treatment facilities that are developed by the other party to the agreement during the five years following the business combination. We recorded an intangible asset of $14.0 million at the acquisition date related to this development agreement.

As part of the other business combination, we entered into an option agreement with the seller of the business whereby we have the option to purchase a water treatment facility that is currently under construction. We recorded an intangible asset of $2.5 million at the acquisition date related to this option agreement.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

Crude Oil Logistics Acquisitions

During the three months ended September 30, 2013, we completed two separate acquisitions of businesses to expand our crude oil logistics business in Texas and Oklahoma. On a combined basis, we issued 175,211 common units, valued at $5.3 million, and paid $67.8 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. The agreement for the acquisition of one of these businesses contemplates a post-closing payment for certain working capital items. We incurred and charged to general and administrative expense during the six months ended September 30, 2013 approximately $0.2 million of costs related to these acquisitions.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these two business combinations. The estimates of fair value reflected as of September 30, 2013 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the three months ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	1,233
Inventories	1,021
Property, plant and equipment:
Vehicles (5-10 years)	2,709
Buildings and leasehold improvements (5-30 years)	260
Crude oil tanks and related equipment (2-30 years)	3,580
Barges and tow boats (20 years)	11,996
Other (3-5 years)	42
Intangible assets:
Customer relationships (3 years)	1,700
Trade names (indefinite life)	530
Goodwill	50,856
Trade accounts payable	(660		)
Accrued expenses	(124		)
Other noncurrent liabilities	(53		)
Fair value of net assets acquired	$	73,090

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	67,834
Value of common units issued	5,256
Total consideration paid	$	73,090

Retail Propane Acquisitions

During the six months ended September 30, 2013, we completed three acquisitions of retail propane businesses. On a combined basis, we paid $5.9 million of cash to acquire these assets and operations. The agreements for the acquisitions of these businesses contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these three business combinations, and as a result the estimates of fair value reflected as of September 30, 2013 are subject to change. We expect to complete this process prior to finalizing our financial statements for the fiscal year ending March 31, 2014.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

Fiscal Year Ended March 31, 2013

Pecos Combination

On November 1, 2012, we completed a business combination whereby we acquired Pecos. The business of Pecos consists primarily of crude oil marketing and logistics operations in Texas and New Mexico. We paid $132.4 million of cash (net of cash acquired) and assumed certain obligations with a value of $10.2 million under certain equipment financing facilities. Also on November 1, 2012, we entered into a call agreement with the former owners of Pecos pursuant to which the former owners of Pecos agreed to purchase a minimum of $45.0 million or a maximum of $60.0 million of common units from us. On November 12, 2012, the former owners purchased 1,834,414 common units from us for $45.0 million pursuant to this call agreement.

During the three months ended September 30, 2013, we completed the acquisition accounting for this business combination. The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of Pecos (in thousands):

				Estimated
				as of
				March 31,
	Final			2013			Difference

Accounts receivable - trade	$	73,609		$	73,704		$	(95	)
Inventories	1,903			1,903			—
Other current assets	1,426			1,426			—
Property, plant and equipment:
Vehicles (5-10 years)	22,097			19,193			2,904
Buildings and leasehold improvements (5-30 years)	1,339			1,248			91
Crude oil tanks and related equipment (2-15 years)	1,099			913			186
Land	223			224			(1		)
Other (3-5 years)	36			177			(141		)
Intangible assets:
Customer relationships	—			8,000			(8,000		)
Trade names (indefinite life)	900			1,000			(100		)
Goodwill	91,747			86,661			5,086
Trade accounts payable	(50,795		)	(50,808		)	13
Accrued expenses	(963		)	(1,020		)	57
Long-term debt	(10,234		)	(10,234		)	—
Fair value of net assets acquired	$	132,387		$	132,387		$	—

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	87,444
Value of common units issued	44,943
Total consideration paid	$	132,387

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

Third Coast Combination

On December 31, 2012, we completed a business combination transaction whereby we acquired all of the membership interests in Third Coast for $43.0 million in cash. The business of Third Coast consists primarily of transporting crude oil via barge. Also on December 31, 2012, we entered into a call agreement with the former owners of Third Coast pursuant to which the former owners of Third Coast agreed to purchase a minimum of $8.0 million or a maximum of $10.0 million of common units from us. On January 11, 2013, the former owners of Third Coast purchased 344,680 common units from us for $8.0 million pursuant to this agreement.

We are in the process of identifying and determining the fair value of the assets and liabilities acquired in the acquisition of Third Coast. The estimates of fair value reflected as of September 30, 2013 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the three months ending December 31, 2013. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

	Estimated As of
	September 30,			March 31,
	2013			2013			Difference

Accounts receivable - trade	$	2,195		$	2,248		$	(53	)
Inventories	140			140			—
Property, plant and equipment:
Barges and tow boats (20 years)	12,883			12,883			—
Other (3-7 years)	30			30			—
Intangible assets:
Customer relationships (3 years)	3,000			4,000			(1,000		)
Trade names (indefinite life)	850			500			350
Goodwill	23,645			22,551			1,094
Other noncurrent assets	2,733			2,733			—
Trade accounts payable	(2,429		)	(2,048		)	(381		)
Accrued expenses	(164		)	(154		)	(10		)
Fair value of net assets acquired	$	42,883		$	42,883		$	—

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	35,000
Value of common units issued	7,883
Total consideration paid	$	42,883

Other Crude Oil Logistics and Water Services Business Combinations

During the year ended March 31, 2013, we completed four separate acquisitions to expand the assets and operations of our crude oil logistics and water services businesses. On a combined basis, we paid $52.6 million in cash and assumed $1.3 million of long-term debt in the form of non-compete agreements. We also issued 516,978 common units, valued at $12.4 million, as partial consideration for one of these acquisitions.

During the three months ended September 30, 2013, we completed the acquisition accounting for these business combinations. The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of these businesses (in thousands):

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

				Estimated
				as of
				March 31,
	Final			2013			Difference

Accounts receivable - trade	$	2,676		$	2,660		$	16
Inventories	191			191			—
Other current assets	737			738			(1		)
Property, plant and equipment:
Land	218			191			27
Vehicles (5-10 years)	853			771			82
Water treatment facilities and related equipment (3-30 years)	13,665			13,322			343
Buildings and leasehold improvements (5-30 years)	895			2,233			(1,338		)
Crude oil tanks and related equipment (2-15 years)	4,510			1,781			2,729
Other (3-5 years)	27			2			25
Construction in progress	490			693			(203		)
Intangible assets:
Customer relationships (5-10 years)	13,125			6,800			6,325
Non-compete agreements (3 years)	164			510			(346		)
Trade names (indefinite life)	2,100			500			1,600
Goodwill	34,451			43,822			(9,371		)
Trade accounts payable	(3,374		)	(3,374		)	—
Accrued expenses	(1,914		)	(2,026		)	112
Long-term debt	(1,340		)	(1,340		)	—
Other noncurrent liabilities	(156		)	(156		)	—
Noncontrolling interest	(2,333		)	(2,333		)	—
Fair value of net assets acquired	$	64,985		$	64,985		$	—

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	52,552
Value of common units issued	12,433
Total consideration paid	$	64,985

We estimated the fair value of the customer relationship intangible assets using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

Note 4 — Earnings per Unit

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

	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(in thousands, except unit and per unit amounts)
Basic and diluted earnings (loss) per common or subordinated unit
Income (loss) attributable to parent equity	$	(941	)	$	10,073		$	(18,574	)	$	(14,577	)
Income allocated to general partner(*)	(2,451		)	(694		)	(4,139		)	(789		)
Income (loss) allocated to limited partners	$	(3,392	)	$	9,379		$	(22,713	)	$	(15,366	)

Income (loss) allocated to:
Common unitholders	$	(2,830	)	$	8,286		$	(19,637	)	$	(13,112	)
Subordinated unitholders	$	(562	)	$	1,093		$	(3,076	)	$	(2,254	)

Weighted average common units outstanding	58,909,389			44,831,836			53,336,969			35,730,492

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

Income (loss) per common unit - basic and diluted	$	(0.05	)	$	0.18		$	(0.37	)	$	(0.37	)

Income (loss) per subordinated unit - basic and diluted	$	(0.09	)	$	0.18		$	(0.52	)	$	(0.38	)

(*) 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 and six-month periods ended September 30, 2013 and 2012.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

Note 5 — Property, Plant and Equipment

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

	September 30,			March 31,
Description and Useful Life	2013			2013
	(in thousands)
Natural gas liquids terminal assets (30 years)	$	64,586		$	63,637
Retail propane equipment (5-20 years)	157,534			152,802
Vehicles (5-10 years)	108,280			85,200
Water treatment facilities and equipment (3-30 years)	150,632			91,601
Crude oil tanks and related equipment (2-30 years)	27,384			21,308
Barges and tow boats (20 years)	33,957			21,135
Information technology equipment (3-5 years)	15,223			12,169
Buildings and leasehold improvements (5-30 years)	45,108			48,394
Land	22,994			21,604
Other (3-10 years)	17,673			17,288
Construction in progress	64,682			31,926
	708,053			567,064
Less: Accumulated depreciation	(76,390		)	(50,127		)
Net property, plant and equipment	$	631,663		$	516,937

Depreciation expense was $13.7 million and $7.7 million for the three months ended September 30, 2013 and 2012, respectively, and $27.2 million and $13.8 million for the six months ended September 30, 2013 and 2012, respectively.

Note 6 — Goodwill and Intangible Assets

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

Balance at March 31, 2013	$	563,146
Revisions to acquisition accounting (Note 3)	(3,191		)
Acquisitions	280,332
Balance at September 30, 2013	$	840,287

Goodwill by reportable segment is as follows:

	September 30,		March 31,
	2013		2013
	(in thousands)
Crude oil logistics	$	302,000	$	244,073
Water services	338,842		119,668
Natural gas liquids logistics	87,136		87,136
Retail propane	112,309		112,269
	$	840,287	$	563,146

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

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

		September 30, 2013				March 31, 2013
		Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Useful Lives	Amount		Amortization		Amount		Amortization
		(in thousands)
Amortizable —
Customer relationships*	3-20 years	$	500,546	$	49,475	$	407,835	$	30,959
Water facility development agreement	5 years	14,000		467		—		—
Lease and other agreements	1-8 years	15,210		8,591		15,210		7,018
Non-compete agreements	2-7 years	11,984		4,338		11,855		2,871
Trade names	3-10 years	2,784		476		2,784		326
Debt issuance costs	5-10 years	21,712		5,443		19,494		2,981
Total amortizable		566,236		68,790		457,178		44,155

Non-amortizable —
Trade names		34,800		—		29,580		—
Water facility option agreement		2,500		—		—		—
Total		$	603,536	$	68,790	$	486,758	$	44,155

* The weighted-average remaining amortization period for customer relationship intangible assets is approximately 10 years.

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

Year Ending March 31,
2014 (six months)	$	29,465
2015	56,816
2016	54,777
2017	51,762
2018	45,891
Thereafter	258,735
	$	497,446

Amortization expense was as follows:

	Three Months Ended				Six Months Ended
	September 30,				September 30,
Recorded in	2013		2012		2013		2012
	(in thousands)
Depreciation and amortization	$	11,324	$	5,654	$	20,600	$	8,820
Cost of sales	949		1,352		1,574		1,552
Interest expense	1,065		835		2,462		1,336
Loss on early extinguishment of debt	—		—		—		5,769
	$	13,338	$	7,841	$	24,636	$	17,477

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

Note 7 — Long-Term Debt

Our long-term debt consists of the following:

	September 30,		March 31,
	2013		2013
	(in thousands)
Revolving credit facility —
Expansion capital loans	$	416,500	$	441,500
Working capital loans	229,500		36,000

Senior notes	250,000		250,000

Other notes payable	18,295		21,562
	914,295		749,062
Less - current maturities	8,229		8,626
Long-term debt	$	906,066	$	740,436

Credit Agreement

The Working Capital Facility had a total capacity of $325.0 million for cash borrowings and letters of credit at September 30, 2013. At September 30, 2013, we had outstanding cash borrowings of $229.5 million and outstanding letters of credit of $85.9 million on the Working Capital Facility, leaving a remaining capacity of $9.6 million at September 30, 2013. The Expansion Capital Facility had a total capacity of $725.0 million for cash borrowings at September 30, 2013. At September 30, 2013, we had outstanding cash borrowings of $416.5 million on the Expansion Capital Facility, leaving a remaining capacity of $308.5 million at September 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 September 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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

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 September 30, 2013, the interest rate in effect on outstanding LIBOR borrowings was 3.19%, calculated as the LIBOR rate of 0.19% plus a margin of 3.0%. At September 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 September 30, 2013, our outstanding borrowings and interest rates under our Revolving Credit Facility were as follows (dollars in thousands):

	Amount		Rate
Expansion Capital Facility —
LIBOR borrowings	$	416,500	3.19	%
Working Capital Facility —
LIBOR borrowings	204,000		3.18	%
Base rate borrowings	25,500		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 September 30, 2013, our leverage ratio was less than 2.5 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 September 30, 2013, our interest coverage ratio was greater than 7.5 to 1.

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

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

As described in Note 14, we entered into an amendment to the Credit Agreement during November 2013. This amendment increased the capacity on the Expansion Capital and Working Capital facilities, extended the maturity date of the Credit Agreement, and reduced the interest rate on LIBOR rate borrowings.

Senior Notes

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”). 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 September 30, 2013, we were in compliance with all covenants under the Note Purchase Agreement and the Senior Notes.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

Senior Unsecured Notes

As described in Note 14, we issued $450.0 million of senior unsecured notes during October 2013. These senior unsecured notes bear interest at a fixed rate of 6.875% and mature on October 15, 2021.

Other Notes Payable

We have executed various non-interest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also have certain notes payable that relate to equipment financing, which have interest rates ranging from 2.1% to 4.9% at September 30, 2013.

Debt Maturity Schedule

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

	Revolving				Other
	Credit		Senior		Notes
Year Ending March 31,	Facility		Notes		Payable		Total
2014 (six months)	$	—	$	—	$	5,780	$	5,780
2015	—		—		6,913		6,913
2016	—		—		3,186		3,186
2017	—		—		1,888		1,888
2018	646,000		25,000		328		671,328
Thereafter	—		225,000		200		225,200
	$	646,000	$	250,000	$	18,295	$	914,295

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.

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

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

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 September 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.

Customer Dispute

A customer of our crude oil logistics segment has disputed the transportation rate schedule we used to bill the customer for services that we provided from November 2012 through February 2013, which was the same rate schedule that Pecos used to bill the customer from April 2011 through October 2012 (prior to our acquisition of Pecos). The customer has not paid $1.7 million of the amount we charged for services we provided from November 2012 through February 2013. In May 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. Later in May 2013, the customer filed an answer and counterclaim seeking to recover $5.5 million that it paid to Pecos prior to our acquisition of Pecos. We have not recorded revenue for the $1.7 million of unpaid fees charged from November 2012 through February 2013, pending resolution of the dispute. During August 2013, the customer notified us that it intended to withhold payment of approximately $3.3 million for services performed by us during the period from June 2013 through August 2013, pending resolution of the dispute, although the customer has not disputed the validity of the amounts billed for services performed during this time frame. Upon receiving this notification, we ceased providing services under this contract, and on November 5, 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. We are not able to reliably predict the outcome of this dispute at this time, but we do not believe the outcome will have a material adverse effect on our consolidated financial position or results of operations.

Canadian Fuel and Sales Taxes

The taxing authority of a province in Canada completed an audit of fuel and sales tax payments and 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 that would be assessed. If we are unsuccessful in demonstrating that these transactions were exempt and if these taxes are ultimately assessed, 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 identified during the audit, 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 amount identified during the audit.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

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 $1.8 million at September 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.

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 September 30, 2013 are as follows (in thousands):

Year Ending March 31,
2014 (six months)	$	31,924
2015	51,652
2016	46,720
2017	44,174
2018	36,636
Thereafter	80,402
Total	$	291,508

Rental expense relating to operating leases was $17.0 million during the three months ended September 30, 2013 and $12.5 million during the three months ended September 30, 2012. Rental expense relating to operating leases was $32.5 million during the six months ended September 30, 2013 and $17.2 million during the six months ended September 30, 2012.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 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 September 30, 2013, we had the following such commitments outstanding:

	Volume	Value
	(in thousands)
Natural gas liquids fixed-price purchase commitments (gallons)	79,041	$	74,356
Natural gas liquids floating-price purchase commitments (gallons)	653,808	722,942
Natural gas liquids fixed-price sale commitments (gallons)	146,432	183,717
Natural gas liquids floating-price sale commitments (gallons)	464,196	561,382

Crude oil floating-price purchase commitments (barrels)	4,963	509,734
Crude oil floating-price sale commitments (barrels)	4,584	522,787

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. We recorded the following expense (benefit) to cost of sales related to the amortization of the assets and liabilities related to these contracts (in thousands):

	Natural Gas		Crude Oil
	Liquids Logistics		Logistics
For the Six Months Ended:	Segment		Segment			Total
September 30, 2013	$	2,420	$	(164	)	$	2,256
September 30, 2012	2,742		(464		)	2,278

At September 30, 2013, the net unamortized balance included in our consolidated balance sheet is a net asset of $0.3 million, which we will amortize to cost of sales during the third and fourth quarters of the fiscal year ending March 31, 2014.

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. The subordination period will 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

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

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.

							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 September 30, 2013, we distributed a total of $33.5 million ($0.49375 per common and subordinated limited partner unit and per general partner notional unit) to our unitholders of record as of August 5, 2013. This included an incentive distribution of $1.7 million to the general partner. On October 23, 2013, we declared a distribution of $0.51125 per common unit, to be paid on November 14, 2013 to unitholders of record on November 4, 2013. This distribution amounts to $38.4 million, including amounts to be paid on common, subordinated, and general partner notional units and the amount to be paid on incentive distribution rights.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

Equity Offerings

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 offering costs of $0.7 million. We used the net proceeds from the offering to reduce the outstanding balance on our Revolving Credit Facility.

On September 25, 2013, we completed a public offering of 4,100,000 common units. We received net proceeds of $127.6 million, after underwriting discounts and commissions of $5.0 million and offering costs of $0.2 million. We used the net proceeds from the offering to reduce the outstanding balance on our Revolving Credit Facility.

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 six months ended September 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 six months ended September 30, 2013:

Unvested restricted units at March 31, 2013	1,444,900
Units granted	323,000
Units vested and issued	(282,692	)
Units withheld for employee taxes	(116,108	)
Units forfeited	(15,000	)
Unvested restricted units at September 30, 2013	1,354,100

The scheduled vesting of the awards is summarized below:

Vesting Date		Number of Awards
January 1, 2014		20,000
July 1, 2014		398,300
January 1, 2015		12,000
July 1, 2015		320,800
January 1, 2016		12,000
July 1, 2016		312,000
January 1, 2017		12,000
July 1, 2017		220,500
January 1, 2018		12,000
July 1, 2018		34,500
Total unvested units at September 30, 2013		1,354,100

On July 1, 2013, 398,800 of the awards vested. We issued 282,692 common units to the recipients and we recorded an increase to equity of $8.6 million. We withheld the remaining 116,108 common units, in return for which we paid $3.5 million of withholding taxes on behalf of the recipients.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

We record the expense for each tranche on a straight-line basis over the period beginning with the vesting of the previous tranche and ending with the vesting of the tranche. We adjust the cumulative expense recorded through the reporting date using the estimated fair value of the awards at the reporting date. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth. The following table summarizes the expense we recorded related to the restricted unit awards during the periods indicated (in thousands):

For the Three Months Ended:
September 30, 2013	$	3,217
September 30, 2012	2,302

For the Six Months Ended:
September 30, 2013	$	10,292
September 30, 2012	2,957

We estimate that the future expense we will record on the unvested awards as of September 30, 2013 will be as follows (in thousands), after taking into consideration an estimate of forfeitures of approximately 77,000 units. For purposes of this calculation, we have used the closing price of the common units on September 30, 2013,which was $30.84.

Year Ending March 31,
2014 (six months)	$	6,404
2015	10,420
2016	9,407
2017	7,217
2018	2,515
2019	240
Total	$	36,203

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 six months ended September 30, 2013	10,292
Value of units vested and issued	(8,619		)
Taxes paid on behalf of participants	(3,530		)
Balance at September 30, 2013	$	3,186

The weighted-average fair value of the awards at September 30, 2013 was $26.03, which was calculated as the closing price of the common units on September 30, 2013, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period.

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 September 30, 2013, approximately 5.3 million units remain available for issuance under the LTIP.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

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.

Commodity Derivatives

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

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	634		$	(2,747	)
Level 2 measurements	9,006			(15,551		)
	9,640			(18,298		)

Netting of counterparty contracts (1)	(5,952		)	5,952
Cash collateral provided	—			2,745
Commodity contracts reported on consolidated balance sheet	$	3,688		$	(9,601	)

(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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

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

	September 30,			March 31,
	2013			2013
	(in thousands)
Prepaid expenses and other current assets	$	3,547		$	5,551
Other noncurrent assets	141			44
Accrued expenses and other payables	(9,154		)	(12,701		)
Other noncurrent liabilities	(447		)	—
Net liability	$	(5,913	)	$	(7,106	)

The following table sets forth our open commodity derivative contract positions at September 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 September 30, 2013 -
Butane cross-commodity (1)	October 2013 — March 2015	858		$	(3,034	)
Crude oil cross-commodity (2)	October 2013 — March 2015	(633	)	(3,875		)
Crude oil fixed-price (3)	October 2013 — September 2014	(927	)	910
Crude oil index (4)	October 2013 — June 2014	434		555
Propane fixed-price (5)	October 2013 — March 2015	(904	)	(1,977		)
Butane fixed-price (6)	October 2013 — March 2014	(464	)	(1,208		)
Other	October 2013 — March 2014	26		(29		)
				(8,658		)
Net cash collateral provided				2,745
Net fair value of commodity derivatives on consolidated balance sheet				$	(5,913	)

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”

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

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 oil 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.

(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 index price differentials 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.

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

We recorded the following net gains (losses) from our commodity derivatives to cost of sales during the periods indicated:

	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(in thousands)
Commodity contracts -
Unrealized gain (loss)	$	(167	)	$	9,476		$	(3,745	)	$	11,405
Realized gain (loss)	(10,505		)	(8,685		)	(14,136		)	(6,386		)
Total	$	(10,672	)	$	791		$	(17,881	)	$	5,019

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.

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

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 30, 2013 and 2012

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 September 30, 2013, we had $620.5 million of debt on our Revolving Credit Facility at a rate of 3.19% and $25.5 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 $0.8 million on the revolving debt balance of $646.0 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. 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. 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. Our natural gas liquids logistics segment consists of two divisions, which are organized based on the locations in which the divisions are headquartered. 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 September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(in thousands)
Revenues:
Crude oil logistics -
Crude oil sales	$	1,013,061		$	712,119		$	1,941,595		$	785,677
Other revenues	9,794			2,214			19,729			2,534
Water services -
Water treatment and disposal	28,823			12,724			47,511			14,236
Other revenues	5,367			3,086			7,192			3,515
Natural gas liquids logistics -
Propane sales	191,437			116,980			315,274			222,824
Other natural gas liquids sales	308,606			244,346			558,459			339,762
Other revenues	9,250			5,495			18,114			8,321
Retail propane -
Propane sales	40,651			37,939			87,342			77,791
Distillate sales	10,562			10,859			28,431			22,623
Other retail sales	8,198			8,205			15,898			15,797
Other	1,485			1,308			2,959			1,461
Elimination of intersegment sales	(33,297		)	(19,765		)	(62,610		)	(32,595		)
Total revenues	$	1,593,937		$	1,135,510		$	2,979,894		$	1,461,946

Depreciation and amortization:
Crude oil logistics	$	3,330		$	1,680		$	8,014		$	1,940
Water services	11,438			2,768			18,794			3,050
Natural gas liquids logistics	2,672			3,553			5,376			5,450
Retail propane	6,871			5,187			14,111			11,928
Other	750			173			1,490			220
Total depreciation and amortization	$	25,061		$	13,361		$	47,785		$	22,588

Operating income (loss):
Crude oil logistics	$	5,884		$	10,129		$	12,493		$	5,819
Water services	2,913			4,377			5,956			4,547
Natural gas liquids logistics	14,605			10,217			12,490			11,402
Retail propane	(4,520		)	(469		)	(6,024		)	(6,640		)
Corporate and other	(8,937		)	(5,669		)	(22,312		)	(11,617		)
Total operating income	$	9,945		$	18,585		$	2,603		$	3,511

Other items not allocated by segment:
Interest expense	(11,060		)	(8,692		)	(21,682		)	(12,492		)
Loss on early extinguishment of debt	—			—			—			(5,769		)
Interest income	266			263			664			629
Other income (expense), net	153			3			(195		)	29
Income tax (expense) benefit	(236		)	(77		)	170			(536		)
Net income (loss)	$	(932	)	$	10,082		$	(18,440	)	$	(14,628	)

Additions to property, plant and equipment, including acquisitions (accrual basis):
Crude oil logistics	$	31,336		$	2,836		$	35,462		$	28,314
Water services	62,473			4,579			70,182			96,357
Natural gas liquids logistics	13,209			3,333			28,316			5,444
Retail propane	4,546			2,536			11,492			57,247
Other	217			1,213			846			13,357
Total	$	111,781		$	14,497		$	146,298		$	200,719

	September 30,			March 31,
	2013			2013
	(in thousands)
Total assets:
Crude oil logistics	$	861,277		$	801,030
Water services	872,095			466,462
Natural gas liquids logistics	758,107			474,141
Retail propane	492,218			513,301
Corporate	42,796			36,413
Total	$	3,026,493		$	2,291,347

Long-lived assets, net:
Crude oil logistics	$	432,886		$	356,750
Water services	844,231			453,986
Natural gas liquids logistics	258,972			238,192
Retail propane	439,577			441,762
Corporate	31,030			31,996
Total	$	2,006,696		$	1,522,686

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 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 our management own interests in entities with which we have purchased products and services from and have sold products and services. The majority of these purchases represent crude oil purchases and are reported within cost of sales in our consolidated statements of operations, although approximately $3.7 million of these transactions during the six months ended September 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 statements of operations.

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

	Three Months Ended				Six Months Ended
	September 30,				September 30,
	2013		2012		2013		2012

Sales to SemGroup	$	3,780	$	11,598	$	3,780	$	24,280
Purchases from SemGroup	28,377		14,529		47,916		27,077
Sales to entities affiliated with management	58,769		1,137		109,872		1,326
Purchases from entities affiliated with management	48,522		13,895		56,346		15,651

Receivables from affiliates consist of the following (in thousands):

	September 30,		March 31,
	2013		2013

Receivables from entities affiliated with management	$	969	$	22,883
Receivables from SemGroup	2,102		—
	$	3,071	$	22,883

Payables to related parties consist of the following (in thousands):

	September 30,		March 31,
	2013		2013

Payables to SemGroup	$	12,841	$	4,601
Payables to entities affiliated with management	5,588		2,299
	$	18,429	$	6,900

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months and Six Months Ended September 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.

We completed a business combination during the three months ended September 30, 2013 with an entity owned by an employee. We paid $11.0 million of cash for this acquisition.

Note 14 — Subsequent Events

Senior Unsecured Notes

On October 16, 2013, we issued $450.0 million of senior unsecured notes (the “Unsecured Notes”) in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”) pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of approximately $438.4 million, after the initial purchasers’ discount of $10.1 million and estimated offering costs of $1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

The Unsecured Notes mature on October 15, 2021. We have the right to redeem the Unsecured Notes prior to the maturity date, although we would be required to pay a premium for early redemption. The notes bear interest at a fixed rate of 6.875%. Interest is payable on April 15 and October 15 of each year.

The purchase agreement and the indenture governing the Unsecured Notes contain various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

We also entered into a registration rights agreement whereby we have committed to exchange the Unsecured Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the Unsecured Notes on or before October 16, 2014. If we are unable to fulfill this obligation, we would be required to pay liquidated damages to the holders of the Unsecured Notes.

Gavilon Acquisition Agreement

On November 5, 2013, we entered into an agreement with Gavilon Energy Intermediate, LLC to acquire 100% of its equity interests in Gavilon, LLC (“Gavilon”), which is a midstream energy business with pipeline terminal and storage assets located in Oklahoma, Texas, and Louisiana. The purchase price is $890 million in cash, subject to adjustment based on a target level of working capital to be delivered by Gavilon at the closing of the transaction. The acquisition agreement contains customary representations, warranties, indemnification obligations and covenants by the parties. The acquisition is expected to close in December 2013, subject to customary closing conditions including the expiration or termination of the waiting period under the Hart-Scott-Rodino Act.

Sale of Common Units

On November 5, 2013, we entered into an agreement to issue and sell 8,110,848 of our common units in a private placement at a price of $29.59 per common unit for approximately $240.0 million. The agreement for the sale of the common units includes customary representations and warranties, conditions, indemnification obligations and covenants by the parties. This sale of common units is subject to customary conditions to closing, and is expected to close in December 2013, concurrent with and contingent upon the closing of the Gavilon acquisition. The agreement will require us to register these units for resale under the Securities Act of 1933 within 90 days of the closing of the sale of the units.

Amendment to Credit Agreement

On November 5, 2013, we entered into an amendment to our Credit Agreement. This amendment increased the capacity on the Expansion Capital Facility from $725.0 million to $785.5 million and increased the capacity on the Working Capital Facility from $325.0 million to $885.5 million. This amendment also extended the maturity date of the agreement from June 19, 2017 to November 5, 2018.

Borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin or (ii) an adjusted LIBOR rate plus a margin. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. The amendment in November 2013 changed the margin on LIBOR rate borrowings from a range of 2.75% to 3.75% to a range of 1.50% to 2.50%. We paid fees of approximately $8.8 million to the lenders related to this amendment.

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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 and six months ended September 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:

· During October 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.

· During February 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 six months ended September 30, 2013, we completed three acquisitions of retail propane and distillate businesses.

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· On July 2, 2013, we completed a business combination with High Roller Wells Big Lake SWD No. 1, Ltd. (“Big Lake”), whereby we acquired a water disposal facility in West Texas. We also entered into a development agreement that provides us the option to purchase water disposal facilities that may be developed in the future.

· On September 1, 2013, we completed a business combination whereby we acquired a crude oil marketing business in Oklahoma and Texas.

· On September 3, 2013, we completed a business combination with Coastal Plains Disposal #1, LLC (“Coastal”), in which we acquired the ownership interests in a water disposal facility in Texas.

As of September 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 oil to different markets. We also seek to maximize margins by blending crude oil of varying properties.

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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
	Low		High		At Period End
For the Three Months Ended:
September 30, 2013	$	97.99	$	110.53	$	102.33
September 30, 2012	83.75		99.00		92.19

For the Six Months Ended:
September 30, 2013	$	86.68	$	110.53	$	102.33
September 30, 2012	77.69		106.16		92.19

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 primary customers of our facilities in Colorado have committed to deliver to our facilities all wastewater produced at wells in a designated area. Most of the customers of our facilities in Texas are not under volume commitments, other than one customer that has committed to deliver 50,000 barrels per day to one of our facilities.

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.

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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:
September 30, 2013	$	0.81	$	1.16	$	1.01	$	0.86	$	1.19	$	1.05
September 30, 2012	0.51		0.88		0.79		0.79		0.99		0.92

For the Six Months Ended:
September 30, 2013	$	0.77	$	1.16	$	1.01	$	0.81	$	1.19	$	1.05
September 30, 2012	0.50		0.96		0.79		0.71		1.22		0.92

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:
September 30, 2013	$	1.19	$	1.44	$	1.38
September 30, 2012	1.23		1.59		1.44

For the Six Months Ended:
September 30, 2013	$	1.08	$	1.44	$	1.38
September 30, 2012	1.14		1.93		1.44

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 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.

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Recent Developments

Senior Unsecured Notes

Gavilon Acquisition Agreement

Sale of Common Units

Amendment to Credit Agreement

Summary Discussion of Operating Results for the Three Months Ended September 30, 2013

During the three months ended September 30, 2013, we generated operating income of $9.9 million, compared to operating income of $18.6 million during the three months ended September 30, 2012.

Our crude oil logistics segment generated operating income of $5.9 million during the three months ended September 30, 2013, compared to operating income of $10.1 million during the three months ended September 30, 2012. Cost of sales was increased by $3.1 million during the three months ended September 30, 2013 due to unrealized losses on derivatives. Cost of sales was reduced by $6.7 million during the three months ended September 30, 2012 due to unrealized gains on derivatives. The impact of these unrealized gains and losses on derivatives impacted the comparability of operating income between the three months ended September 30, 2013 and the three months ended September 30, 2012 by $9.8 million. Acquisitions of business contributed to operating income during the three months ended September 30, 2013, although this benefit was partially offset by a narrowing of price differences between markets, which reduced our opportunities to generate increased margins by transporting product from lower-price to higher-price markets.

Our water services segment generated operating income of $2.9 million during the three months ended September 30, 2013, compared to operating income of $4.4 million during the three months ended September 30, 2012. The decrease in operating income was due primarily to an increase in depreciation and amortization expense, partially offset by operating income generated by water services businesses we acquired subsequent to our merger with High Sierra.

Our natural gas liquids logistics segment generated operating income of $14.6 million during the three months ended September 30, 2013, compared to operating income of $10.2 million during the three months ended September 30, 2012. Market demand was greater during the three months ended September 30, 2013 than during the three months ended September 30, 2012, which resulted in higher sales volumes. Volumes also improved due to the expansion of our sales staff. In addition, during the year ended March 31, 2013, we refurbished two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals. Operating income during the three months ended September 30, 2013 also benefitted from $3.3 million of unrealized gains on derivatives, compared to $1.7 million of unrealized gains on derivatives during the three months ended September 30, 2012.

Our retail propane segment generated an operating loss of $4.5 million during the three months ended September 30, 2013, compared to an operating loss of $0.5 million during the three months ended September 30, 2012. Due to the seasonal nature of demand for propane and distillates, sales volumes of our retail propane business are lower during the first and second quarters of the fiscal year than during the third and fourth quarters of the fiscal year. Sales volumes and product margins during the three months ended September 30, 2013 were similar to volumes and product margins during the three months ended September 30, 2012, except that cost of sales during the three months ended September 30, 2012 were reduced by $1.8 million of unrealized gains on derivatives. These derivatives were entered into as hedges against potential increases in the cost of distillates. During the three months ended September 30, 2013, we have primarily used physical contracts accounted for as normal purchases, rather than financial derivatives, to hedge against potential increases in the cost of distillates. Depreciation and amortization expense was higher during the three months ended September 30, 2013 than during the three months ended September 30, 2012.

We incurred interest expense of $11.1 million during the three months ended September 30, 2013. This was higher than the interest expense of $8.7 million during the three months ended September 30, 2012, due primarily to borrowings to finance acquisitions.

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Consolidated Results of Operations

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

	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(in thousands)
Revenues	$	1,593,937		$	1,135,510		$	2,979,894		$	1,461,946
Cost of sales	1,488,850			1,053,690			2,791,926			1,352,675
Operating and general and administrative expenses	70,081			49,874			137,580			83,172
Depreciation and amortization	25,061			13,361			47,785			22,588
Operating income	9,945			18,585			2,603			3,511
Interest expense	(11,060		)	(8,692		)	(21,682		)	(12,492		)
Loss on early extinguishment of debt	—			—			—			(5,769		)
Interest and other income, net	419			266			469			658
Income (loss) before income taxes	(696		)	10,159			(18,610		)	(14,092		)
Income tax (provision) benefit	(236		)	(77		)	170			(536		)
Net income (loss)	(932		)	10,082			(18,440		)	(14,628		)
Net income allocated to general partner	(2,451		)	(694		)	(4,139		)	(789		)
Net (income) loss attributable to noncontrolling interests	(9		)	(9		)	(134		)	51
Net income (loss) attributable to parent equity allocated to limited partners	$	(3,392	)	$	9,379		$	(22,713	)	$	(15,366	)

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 combinations described above had a significant impact on the comparability of our results of operations for the three months ended September 30, 2013 and 2012.

Interest Expense

The largest component of interest expense during the six months ended September 30, 2013 and 2012 was 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 September 30,
2013	$	572,353	3.63	%	$	250,000	6.65	%
2012	366,283		3.46	%	250,000		6.65	%
Six Months Ended September 30,
2013	$	521,202	3.65	%	$	250,000	6.65	%
2012	320,272		3.61	%	142,077		6.65	%

Interest expense also includes amortization of debt issuance costs, which represented $1.1 million of expense during the three months ended September 30, 2013 and $0.8 million of expense during the three months ended September 30, 2012. Debt issuance costs represented $2.5 million of expense during the six months ended September 30, 2013 and $1.3 million of expense during the six

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months ended September 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 for the six months ended September 30, 2012.

The increased level of debt outstanding during the three months and six months ended September 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 September 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						Six Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(in thousands)
EBITDA:
Net income (loss) attributable to parent equity	$	(941	)	$	10,073		$	(18,574	)	$	(14,577	)
Provision (benefit) for income taxes	236			77			(170		)	536
Interest expense	11,060			8,692			21,682			12,492
Loss on early extinguishment of debt	—			—			—			5,769
Depreciation and amortization expense	25,753			14,699			48,948			24,113
EBITDA	$	36,108		$	33,541		$	51,886		$	28,333
Unrealized (gain) loss on derivative contracts	167			(9,476		)	3,745			(11,405		)
Loss (gain) on disposal of assets	1,790			(30		)	2,163			(23		)
Share-based compensation expense	3,217			2,302			10,292			2,957
Adjusted EBITDA	$	41,282		$	26,337		$	68,086		$	19,862

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 expense. 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 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

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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 September 30, 2013 and 2012

Items Impacting the Comparability of Our Financial Results

Our results of operations for the three months ended September 30, 2013 may not be comparable to our results of operations for the three months ended September 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 September 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 September 30, 2013 and 2012. Volumes shown in the table below for our natural gas liquids logistics segment include sales to our retail segment.

	Three Months Ended
	September 30,
Segment	2013	2012	Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)	9,280	7,479	1,801

Water services
Water delivered (barrels)	16,459	6,036	10,423

Natural gas liquids logistics
Propane sold (gallons)	183,415	137,840	45,575
Other natural gas liquids sold (gallons)	294,809	186,795	108,014

Retail propane
Propane sold (gallons)	20,599	20,057	542
Distillates sold (gallons)	3,072	3,024	48

Volumes sold by our crude oil logistics and water services segments were higher during the three months ended September 30, 2013 than during the three months ended September 30, 2012, due primarily to the expansion of our business through acquisitions.

Volumes sold by our natural gas liquids logistics segment were higher during the three months ended September 30, 2013 than during the three months ended September 30, 2012, due to several factors. Market demand for propane was higher, due in part to colder weather conditions. Market demand for butane to be used in gasoline blending operations was also higher. Volumes also increased due to the expansion of our sales staff. In addition, during the year ended March 31, 2013, we refurbished two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

Volumes sold by our retail propane segment during the three months ended September 30, 2013 were similar to volumes sold during the three months ended September 30, 2012.

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Operating Income (Loss) by Segment

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

	Three Months Ended
	September 30,
Segment	2013			2012			Change
	(in thousands)
Crude oil logistics	$	5,884		$	10,129		$	(4,245	)
Water services	2,913			4,377			(1,464		)
Natural gas liquids logistics	14,605			10,217			4,388
Retail propane	(4,520		)	(469		)	(4,051		)
Corporate and other	(8,937		)	(5,669		)	(3,268		)
Operating income	$	9,945		$	18,585		$	(8,640	)

The operating loss within “corporate and other” for the three months ended September 30, 2013 includes approximately $3.2 million of expense related to equity-based compensation, approximately $0.8 million of expenses related to acquisitions, and approximately $4.7 million of other corporate expenses.

The operating loss within “corporate and other” for the three months ended September 30, 2012 includes approximately $2.3 million of expense related to equity-based compensation, approximately $0.6 million of expenses related to acquisitions, and approximately $3.2 million of other corporate expenses.

The increase in equity-based compensation expense is due in part to the fact that more awards were outstanding during the three months ended September 30, 2013 than during the three months ended September 30, 2012. The increase in expense is also due to the fact that the expense is recorded over the vesting period of the awards, and is adjusted based on the value of the common units at the end of the reporting period. The value of the common units was higher at September 30, 2013 than at September 30, 2012.

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

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

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 September 30, 2013 and 2012 (amounts in thousands).

	Three Months Ended
	September 30,
	2013		2012		Change
Revenues:
Crude oil sales	$	1,013,061	$	712,119	$	300,942
Other revenues	9,794		2,214		7,580
Total revenues(1)	1,022,855		714,333		308,522
Expenses:
Cost of sales	1,000,982		696,999		303,983
Operating expenses	11,760		4,816		6,944
General and administrative expenses	899		709		190
Depreciation and amortization expense	3,330		1,680		1,650
Total expenses	1,016,971		704,204		312,767

Segment operating income	$	5,884	$	10,129	$	(4,245	)

(1) Revenues include $8.8 million of intersegment sales during the three months ended September 30, 2013 and $3.3 million of intersegment sales during the three months ended September 30, 2012 that are eliminated in our consolidated statement of operations.

Revenues. We generated revenue of $1.0 billion from crude oil sales during the three months ended September 30, 2013, selling 9.3 million barrels at an average price of $109.17 per barrel. During the three months ended September 30, 2012, we generated revenue of $712.2 million from crude oil sales, selling 7.5 million barrels at an average price of $95.22 per barrel. The increase in volume during the three months ended September 30, 2013 compared to the three months ended September 30, 2012 was due primarily to acquisitions of crude oil logistics businesses, including Pecos and Third Coast, among others.

Other revenues of our crude oil logistics segment were $9.8 million during the three months ended September 30, 2013, compared to other revenues of $2.2 million during the three months ended September 30, 2012, due primarily to acquisitions of crude oil logistics businesses, including Pecos and Third Coast.

Cost of Sales. Our cost of crude oil sold was $1.0 billion during the three months ended September 30, 2013. We sold 9.3 million barrels at an average cost of $107.86 per barrel. Our cost of sales during the three months ended September 30, 2013 was increased by $3.1 million of unrealized losses and $1.7 million of realized losses on derivatives. During the three months ended September 30, 2012, our cost of crude oil sold was $697.0 million. We sold 7.5 million barrels at an average cost of $93.19 per barrel. Our cost of sales during the three months ended September 30, 2012 was increased by $9.9 million of realized losses on derivatives, which was partially offset by $6.7 million of unrealized gains on derivatives.

Operating Expenses. Our crude oil logistics segment generated $11.8 million of operating expenses during the three months ended September 30, 2013, compared to $4.8 million of operating expenses during the three months ended September 30, 2012. This increase was due primarily to the expansion of operations resulting from acquisitions, including Pecos and Third Coast.

General and Administrative Expenses. Our crude oil logistics segment generated $0.9 million of general and administrative expenses during the three months ended September 30, 2013, compared to $0.7 million of general and administrative expenses during the three months ended September 30, 2012.

Depreciation and Amortization Expense. Our crude oil logistics segment generated depreciation and amortization expense of $3.3 million during the three months ended September 30, 2013, compared to depreciation and amortization expense of $1.7 million during the three months ended September 30, 2012. This increase was due primarily to the expansion of operations resulting from acquisitions.

Operating Income. Our crude oil logistics segment generated operating income of $5.9 million during the three months ended September 30, 2013, compared to operating income of $10.1 million during the three months ended September 30, 2012. Cost of sales was increased by $3.1 million during the three months ended September 30, 2013 due to unrealized losses on derivatives. Cost of sales was decreased by $6.7 million during the three months ended September 30, 2012 due to unrealized gains on derivatives. The impact of these unrealized gains and losses on derivatives impacted the comparability of operating income between the three months ended September 30, 2013 and the three months ended September 30, 2012 by $9.8 million. Acquisitions of businesses contributed to operating income during the three months ended September 30, 2013, although this benefit was partially offset by a narrowing of price differences between markets, which reduced our opportunities to generate increased margins by transporting product from lower-price to higher-price markets.

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Water Services

The following table summarizes the operating results of our water services segment for the three months ended September 30, 2013 and 2012 (amounts in thousands).

	Three Months Ended
	September 30,				Change
	2013		2012		Acquisitions (1)		Other
Revenues:
Water treatment and disposal	$	28,823	$	12,724	$	16,498	$	(399	)
Water transportation	5,367		3,086		3,873		(1,592		)
Total revenues	34,190		15,810		20,371		(1,991		)
Expenses:
Cost of sales	3,782		2,054		2,419		(691		)
Operating expenses	15,003		6,154		10,503		(1,654		)
General and administrative expenses	1,054		457		211		386
Depreciation and amortization expense	11,438		2,768		5,133		3,537
Total expenses	31,277		11,433		18,266		1,578

Segment operating income	$	2,913	$	4,377	$	2,105	$	(3,569	)

(1) Represents the change in revenues and expenses attributable to acquisitions subsequent to the merger with High Sierra.

Revenues. Our water services segment generated $28.8 million of treatment and disposal revenue during the three months ended September 30, 2013, taking delivery of 16.5 million barrels of wastewater at an average revenue of $1.75 per barrel. During the three months ended September 30, 2012, our water services segment generated $12.7 million of treatment and disposal revenue, taking delivery of 6.0 million barrels of wastewater at an average revenue of $2.11 per barrel. The increase in revenues was due primarily to acquisitions, including OWL, Big Lake, and Coastal. The decrease in revenue per barrel is due primarily to the fact that the expansion of our water services business subsequent to our merger with High Sierra has been primarily in Texas, where the market rates for water disposal services are typically lower than in Wyoming and Colorado.

Our water services segment generated transportation revenues of $5.4 million during the three months ended September 30, 2013, compared to transportation revenues of $3.1 million during the three months ended September 30, 2012. This was due to acquisition of OWL, which generated transportation revenues of $3.9 million. This increase was partially offset by a decrease in water transportation revenues generated by the water services business acquired in the merger with High Sierra, which resulted primarily from a slowdown in production activities by a customer.

Cost of Sales. The cost of sales for our water services segment was $3.8 million for the three months ended September 30, 2013. Cost of sales was increased by $0.9 million of realized losses and $0.3 million of unrealized losses on derivatives. Because a portion of our processing revenue is generated from the sale of recovered hydrocarbons, we enter into derivatives to protect against the risk of a decline in the market price of a portion of the hydrocarbons we expect to recover. During the three months ended September 30, 2012, the cost of sales for our water services segment was $2.1 million, which included $0.8 million of unrealized losses and $0.4 million of realized losses on derivatives.

Operating Expenses. Our water services segment generated $15.0 million of operating expenses during the three months ended September 30, 2013, compared to $6.2 million of operating expenses during the three months ended September 30, 2012. This increase was due to acquisitions of businesses. We incurred losses on disposal of property, plant and equipment of $2.0 million during the three months ended September 30, 2013 as a result of property damage resulting from lightning strikes at two of our facilities.

General and Administrative Expenses. Our water services segment generated $1.1 million of general and administrative expenses during the three months ended September 30, 2013, compared to $0.5 million of general and administrative expenses during the three months ended September 30, 2012. This increase was due in part to acquisitions of businesses.

Depreciation and Amortization Expense. Our water services segment generated depreciation and amortization expense of $11.4 million during the three months ended September 30, 2013, compared to depreciation and amortization expense of $2.8 million during the three months ended September 30, 2012. This increase was due primarily to the acquisitions of businesses.

Operating Income. Our water services segment generated $2.9 million of operating income during the three months ended September 30, 2013, compared to operating income of $4.4 million during the three months ended September 30, 2012. The decrease in operating income was due primarily to an increase in depreciation and amortization expense, partially offset by operating income generated by acquired businesses.

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Natural Gas Liquids Logistics

The following table compares the operating results of our natural gas liquids logistics segment for the three months ended September 30, 2013 and 2012:

	Three Months Ended
	September 30,
	2013		2012		Change
	(in thousands)
Revenues:
Propane sales	$	191,437	$	116,980	$	74,457
Other natural gas liquids sales	308,606		244,346		64,260
Other revenues	9,250		5,495		3,755
Total revenues (1)	509,293		366,821		142,472

Expenses:
Cost of sales - propane	184,565		111,870		72,695
Cost of sales - other NGLs	292,142		230,098		62,044
Cost of sales - storage	7,106		2,768		4,338
Operating expenses	6,800		7,128		(328		)
General and administrative expenses	1,403		1,187		216
Depreciation and amortization expense	2,672		3,553		(881		)
Total expenses	494,688		356,604		138,084

Segment operating income	$	14,605	$	10,217	$	4,388

(1) The revenues in this table include $24.4 million of sales to our retail propane and crude oil logistics segments during the three months ended September 30, 2013 and $16.5 million of sales to our retail propane segment during the three months ended September 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 $74.5 million during the three months ended September 30, 2013, as compared to $117.0 million during the three months ended September 30, 2012. This resulted from an increase in the volume sold of 45.6 million gallons, as compared to 137.8 million gallons sold during the three months ended September 30, 2012, and an increase in the sales price per gallon of $0.19 per gallon, as compared to $0.85 per gallon during the three months ended September 30, 2012. The increase in volumes during the three months ended September 30, 2013 as compared to the three months ended September 30, 2012 is due to several factors. Market demand was higher, due in part to colder weather conditions. Volumes also increased due to the expansion of our sales staff. In addition, during the year ended March 31, 2013, we refurbished two terminals that we 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 $64.3 million during the three months ended September 30, 2013, as compared to $244.3 million during the three months ended September 30, 2012. This resulted from an increase in volume sold of 108.0 million gallons, as compared to 186.8 million gallons sold during the three months ended September 30, 2012, partially offset by a decrease in the sales price per gallon of $0.26 per gallon, as compared to $1.31 per gallon during the three months ended September 30, 2012. The increase in volumes during the three months ended September 30, 2013 as compared to the three months ended September 30, 2012 is due to several factors. Market demand for butane to be used in gasoline blending operations was higher. Volumes also increased due to the expansion of our sales staff and to an increased focus on the opportunity to more fully utilize our terminals to market butane.

Cost of Sales. Costs of wholesale propane sales increased approximately $72.7 million during the three months ended September 30, 2013, as compared to $111.9 million during the three months ended September 30, 2012. This resulted from an increase in the volume sold of 45.6 million gallons, as compared to 137.8 million gallons sold during the three months ended September 30, 2012 and an increase in the cost per gallon of $0.20, as compared to $0.81 per gallon during the three months ended

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September 30, 2012. Cost of propane sales during the three months ended September 30, 2013 were increased by $4.0 million of net losses on derivatives, which included $3.6 million of unrealized losses and $0.4 million of realized losses. Cost of propane sales during the three months ended September 30, 2012 were increased by $1.9 million of unrealized losses on derivatives, which was partially offset by $1.1 million of realized gains on derivatives.

Cost of wholesale sales of other natural gas liquids increased approximately $62.0 million during the three months ended September 30, 2013, as compared to $230.1 million during the three months ended September 30, 2012. This resulted from an increase in volume sold of approximately 108.0 million gallons as compared to 186.8 million gallons sold during the three months ended September 30, 2012, partially offset by a decrease in the average cost of $0.24 per gallon, as compared to $1.23 per gallon in the prior year. Cost of sales of other natural gas liquids during the three months ended September 30, 2013 were increased by $7.4 million of realized losses on derivatives, which was partially offset by $6.9 million of realized gains on derivatives. Cost of sales of other natural gas liquids during the three months ended September 30, 2012 were reduced by $3.7 million of unrealized gains and $0.5 million of realized gains on derivatives.

Operating Expenses. Operating expenses of our natural gas liquids logistics segment decreased approximately $0.3 million during the three months ended September 30, 2013 as compared to operating expenses of $7.1 million during the three months ended September 30, 2012.

General and Administrative Expenses. General and administrative expenses of our natural gas liquids logistics segment increased approximately $0.2 million during the three months ended September 30, 2013 as compared to general and administrative expenses of $1.2 million during the three months ended September 30, 2012.

Depreciation and Amortization Expense. Depreciation and amortization expense of our natural gas liquids logistics segment decreased approximately $0.9 million during the three months ended September 30, 2013, as compared to depreciation and amortization expense of approximately $3.6 million during the three months ended September 30, 2012.

Operating Income. Our natural gas liquids logistics segment generated operating income of $14.6 million during the three months ended September 30, 2013 as compared to operating income of $10.2 million during the three months ended September 30, 2012.

Retail Propane

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

	Three Months Ended
	September 30,
	2013			2012			Change
	(in thousands)
Revenues:
Propane sales	$	40,651		$	37,939		$	2,712
Distillate sales	10,562			10,859			(297		)
Other revenues	8,198			8,205			(7		)
Total revenues	59,411			57,003			2,408
Expenses:
Cost of sales - propane	21,848			19,296			2,552
Cost of sales - distillates	9,265			7,276			1,989
Cost of sales - other	2,457			3,094			(637		)
Operating expenses	20,997			20,626			371
General and administrative expenses	2,493			1,993			500
Depreciation and amortization expense	6,871			5,187			1,684
Total expenses	63,931			57,472			6,459

Segment operating loss	$	(4,520	)	$	(469	)	$	(4,051	)

Revenues. Propane sales for the three months ended September 30, 2013 increased approximately $2.7 million as compared to propane sales of $37.9 million during the three months ended September 30, 2012. The increase in revenue was due primarily to an increase in the average price per gallon sold of $0.08, as compared to an average price per gallon sold of $1.89 during the three

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months ended September 30, 2012. The increase in revenues was also due in part to an increase of 0.5 million gallons sold, as compared to 20.1 million gallons sold during the three months ended September 30, 2012.

Distillate sales for the three months ended September 30, 2013 decreased approximately $0.3 million as compared to distillate sales of $10.9 million during the three months ended September 30, 2012, due primarily to a decrease in the average selling price of $0.15 per gallon, as compared to an average selling price of $3.59 per gallon during the three months ended September 30, 2012.

Cost of Sales. Propane cost of sales for the three months ended September 30, 2013 increased approximately $2.6 million as compared to propane cost of sales of $19.3 million during the three months ended September 30, 2012. This increase was due primarily to an increase in the average cost per gallon sold of $0.10, as compared to an average cost per gallon sold of $0.96 during the three months ended September 30, 2012. The increase in cost of sales was also due in part to an increase of 0.5 million gallons sold, as compared to 20.1 million gallons sold during the three months ended September 30, 2012.

Distillate cost of sales for the three months ended September 30, 2013 increased approximately $2.0 million as compared to distillate cost of sales of $7.3 million during the three months ended September 30, 2012. This increase was due primarily to an increase in the cost per gallon sold of $0.61, as compared to a cost per gallon sold of $2.41 during the three months ended September 30, 2012. Cost of distillate sales during the three months ended September 30, 2012 were reduced by $1.8 million of unrealized gains on derivatives.

Operating Expenses. Operating expenses of our retail propane segment increased approximately $0.4 million during the three months ended September 30, 2013 as compared to operating expenses of $20.6 million during the three months ended September 30, 2012.

General and Administrative Expenses. General and administrative expenses of our retail propane segment increased approximately $0.5 million during the three months ended September 30, 2013 as compared to general and administrative expenses of $2.0 million during the three months ended September 30, 2012.

Depreciation and Amortization Expense. Depreciation and amortization expense of our retail propane segment increased approximately $1.7 million during the three months ended September 30, 2013 as compared to depreciation and amortization expense of $5.2 million during the three months ended September 30, 2012.

Operating Loss. Our retail propane segment had an operating loss of approximately $4.5 million during the three months ended September 30, 2013 compared to an operating loss of $0.5 million during the three months ended September 30, 2012. The increased operating loss was due in part to lower product margins on distillate sales; during the three months ended September 30, 2012, distillate cost of sales was reduced by $1.8 million due to unrealized gains on derivatives. Increased depreciation and amortization expense also contributed to the increased operating loss.

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Segment Operating Results for the Six Months Ended September 30, 2013 and 2012

Items Impacting the Comparability of Our Financial Results

Our results of operations for the six months ended September 30, 2013 may not be comparable to our results of operations for the six months ended September 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 six months ended September 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 six months ended September 30, 2013 and 2012. Volumes shown in the table below for our natural gas liquids logistics segment include sales to our retail segment.

	Six Months Ended
	September 30,
Segment	2013	2012	Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)	18,535	8,461	10,074

Water services
Water delivered (barrels)	26,498	6,775	19,723

Natural gas liquids logistics
Propane sold (gallons)	310,834	256,755	54,079
Other natural gas liquids sold (gallons)	544,061	251,750	292,311

Retail propane
Propane sold (gallons)	43,992	39,327	4,665
Distillates sold (gallons)	8,176	6,273	1,903

Volumes sold by our crude oil logistics and water services segments were higher during the six months ended September 30, 2013 than during the six months ended September 30, 2012, due primarily to the expansion of our business through acquisitions and to the fact that we did not acquire these segments until our June 19, 2012 merger with High Sierra.

Volumes sold by our natural gas liquids logistics segment were higher during the six months ended September 30, 2013 than during the six months ended September 30, 2012, due to several factors. Market demand for propane was higher, due in part to colder weather conditions. Market demand for butane to be used in gasoline blending operations was also higher. Volumes also increased due to the expansion of our sales staff. In addition, during the year ended March 31, 2013, we refurbished two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

Volumes sold by our retail propane were higher during the six months ended September 30, 2013 than during the six months ended September 30, 2012, due to improved market demand and to the acquisition of Downeast Energy Corp (“Downeast”) on May 1, 2012.

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Operating Income (Loss) by Segment

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

	Six Months Ended
	September 30,
Segment	2013			2012			Change
	(in thousands)
Crude oil logistics	$	12,493		$	5,819		$	6,674
Water services	5,956			4,547			1,409
Natural gas liquids logistics	12,490			11,402			1,088
Retail propane	(6,024		)	(6,640		)	616
Corporate and other	(22,312		)	(11,617		)	(10,695		)
Operating income	$	2,603		$	3,511		$	(908	)

The operating loss within “corporate and other” for the six months ended September 30, 2013 includes approximately $10.3 million of expense related to equity-based compensation, approximately $1.4 million of expenses related to acquisitions, and approximately $10.4 million of other corporate expenses.

The operating loss within “corporate and other” for the six months ended September 30, 2012 includes approximately $3.0 million of expense related to equity-based compensation, approximately $4.4 million of expenses related to acquisitions, and approximately $4.7 million of other corporate expenses.

The increase in equity-based compensation is due in part to the timing of the grants and is also due in part to an increase in the market value of our common units. 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 expense is adjusted during the vesting period based on the market value of the common units on the reporting date. The value of the common units was higher at September 30, 2013 than at September 30, 2012.

The decrease in acquisition-related expenses is due primarily to the fact that $3.7 million of expense was recorded during the six months ended September 30, 2012 related to the merger with High Sierra.

The operations of our compressor leasing business are also included within “corporate and other.”

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Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the six months ended September 30, 2013 and 2012 (amounts in thousands).

	Six Months Ended
	September 30,
	2013		2012		Change
Revenues:
Crude oil sales	$	1,941,595	$	785,677	$	1,155,918
Other revenues	19,729		2,534		17,195
Total revenues(1)	1,961,324		788,211		1,173,113
Expenses:
Cost of sales	1,917,876		774,243		1,143,633
Operating expenses	21,175		5,426		15,749
General and administrative expenses	1,766		783		983
Depreciation and amortization expense	8,014		1,940		6,074
Total expenses	1,948,831		782,392		1,166,439

Segment operating income	$	12,493	$	5,819	$	6,674

(1) Revenues include $16.5 million of intersegment sales during the six months ended September 30, 2013 and $3.7 million of intersegment sales during the six months ended September 30, 2012 that are eliminated in our consolidated statements of operations.

Revenues. Revenues from crude oil sales increased approximately $1.2 billion during the six months ended September 30, 2013, as compared to revenues from sales of crude oil of $785.7 million during the six months ended September 30, 2012. This resulted from an increase in volume sold of 10.1 million barrels, as compared to 8.5 million barrels sold during the six months ended September 30, 2012, and to an increase in the average sales price of $11.89 per barrel, compared to an average sales price per barrel of $92.86 during the six months ended September 30, 2012. The increase in volume sold is due in part to the fact that we did not own a crude oil logistics business for the full six months ended September 30, 2012, as we did not own this business until our June 19, 2012 merger with High Sierra. The increase is volume is also due to subsequent acquisitions of crude oil logistics businesses, including Pecos and Third Coast, among others.

Other revenues include transportation and terminalling fees. These revenues increased by $17.2 million during the six months ended September 30, 2013, as compared to revenues of $2.5 million during the six months ended September 30, 2012. The increase in other revenues is due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and is also due in part to subsequent acquisitions of crude oil logistics businesses.

Cost of Sales. Cost of crude oil sold increased approximately $1.1 billion during the six months ended September 30, 2013, as compared to cost of crude oil sold of $774.2 million during the six months ended September 30, 2012. This resulted from an increase in volume sold of 10.1 million barrels, as compared to 8.5 million barrels sold during the six months ended September 30, 2012, and to an increase in the average cost of $11.96 per barrel, compared to an average cost per barrel of $91.51 during the six months ended September 30, 2012. During the six months ended September 30, 2013, cost of sales was increased by $1.8 million of realized losses on derivatives, which was partially offset by $1.5 million of unrealized gains on derivatives. During the six months ended September 30, 2012, cost of sales was increased by $8.2 million of realized losses on derivatives, which was partially offset by $2.0 million of unrealized gains on derivatives.

Operating Expenses. Operating expenses of our crude oil logistics segment increased approximately $15.7 million during the six months ended September 30, 2013, compared to operating expenses of $5.4 million during the six months ended September 30, 2012. This increase is due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and is also due in part to subsequent acquisitions of crude oil logistics businesses.

General and Administrative Expenses. General and administrative expenses of our crude oil logistics segment increased approximately $1.0 million during the six months ended September 30, 2013, compared to general and administrative expenses of $0.8 million during the six months ended September 30, 2012. This increase is due primarily to the fact that we did not own a crude

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oil logistics business until our June 19, 2012 merger with High Sierra, and is also due in part to subsequent acquisitions of crude oil logistics businesses.

Depreciation and Amortization Expense. Depreciation and amortization expense of our crude oil logistics segment increased approximately $6.1 million during the six months ended September 30, 2013, compared to depreciation and amortization expense of $1.9 million during the six months ended September 30, 2012. This increase is due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and is also due in part to subsequent acquisitions of crude oil logistics businesses.

Operating Income. Operating income of our crude oil logistics segment was higher during the six months ended September 30, 2013 than during the six months ended September 30, 2012. Acquisitions of business contributed to operating income during the three months ended September 30, 2013, although this benefit was partially offset by a narrowing of price differences between markets, which reduced our opportunities to generate increased margins by transporting product from lower-price to higher-price markets.

Water Services

The following table summarizes the operating results of our water services segment for the six months ended September 30, 2013 and 2012 (amounts in thousands).

	Six Months Ended
	September 30,				Change
	2013		2012		Acquisitions (1)		Other
Revenues:
Water treatment and disposal	$	47,511	$	14,236	$	23,295	$	9,980
Water transportation	7,192		3,515		3,873		(196		)
Total revenues	54,703		17,751		27,168		9,784
Expenses:
Cost of sales	4,365		2,670		2,419		(724		)
Operating expenses	24,010		6,958		13,648		3,404
General and administrative expenses	1,578		526		278		774
Depreciation and amortization expense	18,794		3,050		5,628		10,116
Total expenses	48,747		13,204		21,973		13,570

Segment operating income	$	5,956	$	4,547	$	5,195	$	(3,786	)

(1) Represents the change in revenues and expenses attributable to acquisitions subsequent to the merger with High Sierra.

Revenues. Water treatment and disposal revenues of our water services segment increased approximately $33.3 million during the six months ended September 30, 2013, compared to water treatment and disposal revenues of $14.2 million during the six months ended September 30, 2012. This was due primarily to an increase in volume delivered of 19.7 million barrels, compared to 6.8 million barrels during the six months ended September 30, 2012. The increase in volume of water delivered is due primarily to the fact that we did not own a water services business until our June 19, 2012 merger with High Sierra and due also to subsequent acquisitions of water services businesses. The average revenue per barrel processed declined approximately $0.31 per barrel, as compared to revenue per barrel processed of $2.10 during the six months ended September 30, 2012. The expansion of our water services business subsequent to our merger with High Sierra has been primarily in Texas, where the market rates for water disposal services are typically lower than in Wyoming or Colorado.

Water transportation revenues increased $3.7 million during the six months ended September 30, 2013, compared to revenues of $3.5 million during the six months ended September 30, 2012. This increase was due primarily to the August 2, 2013 acquisition of OWL.

Cost of Sales. Cost of sales increased by approximately $1.7 million during the six months ended September 30, 2013, as compared to cost of sales of $2.7 million during the six months ended September 30, 2012. The increase was due primarily to the expansion of our operations through acquisitions. This was partially offset by the fact that cost of sales during the six months ended

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September 30, 2013 were reduced by $0.3 million of unrealized gains on derivatives, whereas costs of sales during the six months ended September 30, 2012 were increased by $1.3 million of unrealized losses on derivatives.

Operating Expenses. Operating expenses of our water services segment increased approximately $17.1 million during the six months ended September 30, 2013, compared to operating expenses of $7.0 million during the six months ended September 30, 2012. This increase is due primarily to the fact that we did not own a water services business until our June 19, 2012 merger with High Sierra, and is also due in part to subsequent acquisitions of water services businesses. We incurred losses on disposal of property, plant and equipment of $2.0 million during the three months ended September 30, 2013 as a result of property damage resulting from lightning strikes at two of our facilities.

General and Administrative Expenses. General and administrative expenses of our water services segment increased approximately $1.1 million during the six months ended September 30, 2013, compared to general and administrative expenses of $0.5 million during the six months ended September 30, 2012. This increase is due in part to the fact that we did not own a water services business until our June 19, 2012 merger with High Sierra, and is also due in part to subsequent acquisitions of water services businesses.

Depreciation and Amortization Expense. Depreciation and amortization expense of our water services segment increased approximately $15.7 million during the six months ended September 30, 2013, compared to depreciation and amortization expense of $3.1 million during the six months ended September 30, 2012. This increase is due in part to the fact that we did not own a water services business until our June 19, 2012 merger with High Sierra, and is also due in part to subsequent acquisitions of water services businesses.

Operating Income. Operating income of our water services segment increased approximately $1.4 million during the six months ended September 30, 2013, compared to operating income of $4.5 million during the six months ended September 30, 2012. This was due to expanded operations through acquisitions, partially offset by losses of $2.0 million during the six months ended September 30, 2013 as a result of property damage resulting from lightning strikes at two of our facilities and also partially offset by increased depreciation and amortization expense.

Natural Gas Liquids Logistics

The following table summarizes the operating results of our natural gas liquids logistics segment for the six months ended September 30, 2013 and 2012 (amounts in thousands).

	Six Months Ended
	September 30,
	2013		2012		Change
	(in thousands)
Revenues:
Propane sales	$	315,274	$	222,824	$	92,450
Other natural gas liquids sales	558,459		339,762		218,697
Other revenues	18,114		8,321		9,793
Total revenues (1)	891,847		570,907		320,940

Expenses:
Cost of sales - propane	302,108		208,161		93,947
Cost of sales - other NGLs	541,077		327,951		213,126
Cost of sales - storage	12,474		5,138		7,336
Operating expenses	15,532		10,506		5,026
General and administrative expenses	2,790		2,299		491
Depreciation and amortization expense	5,376		5,450		(74		)
Total expenses	879,357		559,505		319,852

Segment operating income	$	12,490	$	11,402	$	1,088

(1) Revenues include $46.0 million of intersegment sales during the six months ended September 30, 2013 and $28.9 million of intersegment sales during the six months ended September 30, 2012 that are eliminated in our consolidated statements of operations.

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Revenues. Revenues from wholesale propane sales increased approximately $92.5 million during the six months ended September 30, 2013, compared to wholesale propane sales of $222.8 million during the six months ended September 30, 2012. This resulted from an increase in the volume sold of 54.1 million gallons, compared to 256.8 million gallons sold during the six months ended September 30, 2012, and to an increase in the price per gallon sold of approximately $0.14, compared to an average price per gallon sold of $0.87 during the six months ended September 30, 2012. Approximately 17.6 million gallons of the increase in volume sold was due to the fact that we only owned the natural gas liquids business of High Sierra for a part of the six months ended September 30, 2012. The remaining increase in volume is due to several factors. Market demand was higher, due in part to colder weather conditions. Volumes also increased due to the expansion of our sales staff. In addition, during the year ended March 31, 2013, we refurbished two terminals that we 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 $218.7 million during the six months ended September 30, 2013, compared to sales of $339.8 million during the six months ended September 30, 2012. This resulted from an increase in the volume sold of 292.3 million gallons, compared to 251.8 million gallons sold during the six months ended September 30, 2012, partially offset by a decrease in the price per gallon sold of approximately $0.32, compared to an average price per gallon sold of $1.35 during the six months ended September 30, 2012. Approximately 169.5 million gallons of the increase in volume sold was due to the fact that we only owned the natural gas liquids business of High Sierra for a part of the six months ended September 30, 2012. The remaining increase in volume is due to several factors. Market demand for butane to be used in gasoline blending operations was higher. Volumes also increased due to the expansion of our sales staff and to an increased focus on the opportunity to more fully utilize our terminals to market butane.

Cost of Sales. Cost of wholesale propane sales increased approximately $93.9 million during the six months ended September 30, 2013, compared to cost of wholesale propane sales of $208.2 million during the six months ended September 30, 2012. This resulted from an increase in the volume sold of 54.1 million gallons, compared to 256.8 million gallons sold during the six months ended September 30, 2012, and to an increase in the cost per gallon sold of approximately $0.16, compared to an average cost per gallon sold of $0.81 during the six months ended September 30, 2012. Cost per gallon sold during the six months ended September 30, 2013 included $5.2 million of unrealized losses on derivatives, which was partially offset by $2.3 million of realized gains on derivatives. Cost per gallon sold during the six months ended September 30, 2012 was reduced by $11.1 million of unrealized gains and $2.2 million of realized gains on derivatives.

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

Cost of wholesale sales of other natural gas liquids increased approximately $213.1 million during the six months ended September 30, 2013, compared to cost of sales of $328.0 million during the six months ended September 30, 2012. This resulted from an increase in the volume sold of 292.3 million gallons, compared to 251.8 million gallons sold during the six months ended September 30, 2012, partially offset by a decrease in the cost per gallon sold of approximately $0.31, compared to an average cost per gallon sold of $1.30 during the six months ended September 30, 2012. Cost of sales of other natural gas liquids during the six months ended September 30, 2013 included $13.5 million of realized losses and $0.3 million of unrealized losses on derivatives. Cost of sales of other natural gas liquids during the six months ended September 30, 2012 included $1.3 million of unrealized losses and $0.1 million of realized losses on derivatives.

Operating Expenses. Operating expenses of our natural gas liquids logistics segment increased approximately $5.0 million during the six months ended September 30, 2013, compared to operating expenses of $10.5 million during the six months ended September 30, 2012, due to expanded operations.

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General and Administrative Expenses. General and administrative expenses of our natural gas liquids logistics segment increased approximately $0.5 million during the six months ended September 30, 2013, compared to general and administrative expenses of $2.3 million during the six months ended September 30, 2012.

Depreciation and Amortization Expense. Depreciation and amortization expense of our natural gas liquids logistics segment decreased approximately $0.1 million during the six months ended September 30, 2013, compared to depreciation and amortization expense of $5.5 million during the six months ended September 30, 2012.

Operating Income. Operating income of our natural gas liquids logistics segment increased approximately $1.1 million during the six months ended September 30, 2013, compared to operating income of $11.4 million during the six months ended September 30, 2012.

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Retail Propane

The following table summarizes the operating results of our retail propane segment for the six months ended September 30, 2013 and 2012 (amounts in thousands).

	Six Months Ended
	September 30,
	2013			2012			Change
	(in thousands)
Revenues:
Propane sales	$	87,342		$	77,791		$	9,551
Distillate sales	28,431			22,623			5,808
Other revenues	15,898			15,797			101
Total revenues	131,671			116,211			15,460
Expenses:
Cost of sales - propane	47,027			42,489			4,538
Cost of sales - distillates	24,509			18,897			5,612
Cost of sales - other	5,100			5,721			(621		)
Operating expenses	41,839			39,068			2,771
General and administrative expenses	5,109			4,748			361
Depreciation and amortization expense	14,111			11,928			2,183
Total expenses	137,695			122,851			14,844

Segment operating loss	$	(6,024	)	$	(6,640	)	$	616

Revenues. Propane sales for the six months ended September 30, 2013 increased approximately $9.6 million, compared to $77.8 million of propane sales during the six months ended September 30, 2012. Propane sales revenues were higher during the six months ended September 30, 2013 than during the six months ended September 30, 2012, due primarily to an increase in volume sold of 4.7 million gallons, compared to 39.3 million gallons sold during the six months ended September 30, 2012. The increase in volume sold was due primarily to colder weather conditions. The average price per gallon sold increased by $0.01, compared to an average price per gallon sold of $1.98 during the six months ended September 30, 2012.

Distillate sales for the six months ended September 30, 2013 increased approximately $5.8 million as compared to distillate sales of $22.6 million during the six months ended September 30, 2012, primarily due to an increase in the volume sold of 1.9 million gallons, as compared to a volume sold of 6.3 million gallons in the prior year. This increase in volume was due primarily to the fact that we acquired Downeast on May 1, 2012, and Downeast was only included in our results of operations for five of the months in the six month period ended September 30, 2012. The increase in revenues resulting from the increase in sales volume was partially offset by a decrease in the average price per gallon sold of $0.13, compared to an average price per gallon sold of $3.61 during the six months ended September 30, 2012.

Cost of Sales. Propane cost of sales for the six months ended September 30, 2013 increased approximately $4.5 million, compared to $42.5 million during the six months ended September 30, 2012. This increase was due primarily to an increase in the volume sold of 4.7 million gallons, compared to 39.3 million gallons sold during the six months ended September 30, 2012. The average cost per gallon sold decreased by $0.01 per gallon, compared to an average cost per gallon sold of $1.08 during the six months ended September 30, 2012.

Distillate cost of sales for the six months ended September 30, 2013 increased approximately $5.6 million, compared to $18.9 million during the six months ended September 30, 2012. This increase was due primarily to an increase in the volume sold of 1.9 million gallons, compared to 6.3 million gallons sold during the six months ended September 30, 2012. The average cost per gallon sold decreased by $0.01 per gallon, compared to an average cost per gallon sold of $3.01 during the six months ended September 30, 2012. Cost of distillate sales during the six months ended September 30, 2012 were reduced by $0.9 million of unrealized gains on derivatives.

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Operating Expenses. Operating expenses of our retail propane segment increased approximately $2.8 million during the six months ended September 30, 2013, compared to operating expenses of $39.1 million during the six months ended September 30, 2012. This increase was due in part to the inclusion of Downeast in our results of operations for the full six months ended September 30, 2013, as compared to only five of the months in the six month period ended September 30, 2012.

General and Administrative Expenses. General and administrative expenses of our retail propane segment increased approximately $0.4 million during the six months ended September 30, 2013, compared to general and administrative expenses of $4.7 million during the six months ended September 30, 2012. This increase was due in part to the inclusion of Downeast in our results of operations for the full six months ended September 30, 2013, as compared to only five of the months in the six month period ended September 30, 2012.

Depreciation and Amortization Expense. Depreciation and amortization expense of our retail propane segment increased approximately $2.2 million during the six months ended September 30, 2013, compared to depreciation and amortization expense of $11.9 million during the six months ended September 30, 2012. This increase was due in part to the inclusion of Downeast in our results of operations for the full six months ended September 30, 2013, as compared to only five of the months in the six month period ended September 30, 2012.

Operating Loss. Operating loss of our retail propane segment decreased approximately $0.6 million during the six months ended September 30, 2013, compared to an operating loss of $6.6 million during the six months ended September 30, 2012.

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.

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) are sufficient to meet our liquidity needs. 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.

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Credit Agreement

On June 19, 2012, we entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility”, and together with the Working Capital Facility, the “Revolving Credit Facility”). The Working Capital Facility had a total capacity of $325.0 million for cash borrowings and letters of credit at September 30, 2013. At September 30, 2013, we had outstanding cash borrowings of $229.5 million and outstanding letters of credit of $85.9 million on the Working Capital Facility, leaving a remaining capacity of $9.6 million at September 30, 2013. The Expansion Capital Facility had a total capacity of $725.0 million for cash borrowings at September 30, 2013. At September 30, 2013, we had outstanding cash borrowings of $416.5 million on the Expansion Capital Facility, leaving a remaining capacity of $308.5 million at September 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 September 30, 2013, the borrowing base provisions of the Credit Agreement did not have any impact on the capacity available under the Working Capital Facility.

	Amount		Rate
Expansion Capital Facility —
LIBOR borrowings	$	416,500	3.19	%
Working Capital Facility —
LIBOR borrowings	204,000		3.18	%
Base rate borrowings	25,500		5.25	%

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

As described above under “Recent Developments”, we entered into an amendment to the Credit Agreement during November 2013. This amendment increased the capacity on the Expansion Capital and Working Capital facilities, extended the maturity date of the Credit Agreement, and reduced the interest rate on LIBOR rate borrowings.

Senior Notes

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”). 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.

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

Senior Unsecured Notes

As described above under “Recent Developments”, we issued $450.0 million of senior unsecured notes during October 2013. These senior unsecured notes bear interest at a fixed rate of 6.875% and mature on October 15, 2021.

Previous Credit Facilities

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Revolving Credit Balances

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

	Daily Average		Lowest		Highest
	Balance		Balance		Balance
Six Months Ended September 30, 2013:
Expansion loans	$	440,423	$	255,000	$	546,000
Working capital loans	80,779		—		229,500

Six Months Ended September 30, 2012:
New credit facility (June 19 - September 30) —
Expansion loans	$	256,385	$	254,000	$	262,000
Working capital loans	106,322		70,000		139,000
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):

	Six Months Ended September 30,
Cash Flows Provided by (Used In):	2013			2012

Operating activities, before changes in operating assets and liabilities	$	60,976		$	14,960
Changes in operating assets and liabilities	(109,317		)	(67,766		)

Operating activities	$	(48,341	)	$	(52,806	)

Investing activities	(477,257		)	(309,977		)

Financing activities	519,565			380,960

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.

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 borrow under our Revolving Credit Facility to supplement our operating cash flows as needed during our first and second quarters.

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.

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During the six months ended September 30, 2013, we completed a number of business combinations for which we paid $393.0 million of cash, net of cash acquired, on a combined basis. Also during the six months ended September 30, 2013, we paid $67.4 million for capital expenditures, which related primarily to water disposal and natural gas liquids terminal assets. Of this amount, approximately $52.4 million represented expansion capital and approximately $15.0 million represented maintenance capital.

During the six months ended September 30, 2012, we completed our merger with High Sierra, for which we paid $239.3 million, net of cash acquired. Also, during the six months ended September 30, 2012, we completed five other acquisitions, for which we paid $67.8 million of cash, net of cash acquired, on a combined basis.

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 six months ended September 30, 2013, we borrowed $168.5 million on our Revolving Credit Facility (net of repayments). During the six months ended September 30, 2012, we borrowed $172.0 million on our revolving credit facilities (net of repayments) and issued $250.0 million of Senior Notes. During the six months ended September 30, 2012, we paid $17.8 million of debt issuance costs.

Cash flows from financing activities include proceeds from sales of equity. During the six months ended September 30, 2013, we completed two equity offerings for which we received net proceeds of $415.1 million on a combined basis.

Cash flows from financing activities also include distributions paid to owners. We expect our distributions to our partners to increase in future periods under the terms of our partnership agreement. Based on the number of common and subordinated units outstanding at September 30, 2013 (exclusive of unvested restricted units issued pursuant to employee and director compensation programs), if we made distributions equal to our minimum quarterly distribution of $0.3375 per unit ($1.35 annualized), total distributions would equal $24.1 million per quarter ($96.2 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
October 23, 2013	November 4, 2013	November 14, 2013	0.5113		35,908		2,491

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Contractual Obligations

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

			For the
			Six 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	$	416,500	$	—	$	—	$	—	$	—	$	416,500
Working capital borrowings	229,500		—		—		—		—		229,500
Senior notes	250,000		—		—		—		—		250,000
Other long-term debt	18,295		5,780		6,913		3,186		1,888		528
Interest payments on long-term debt —	—		—		—		—		—		—
Revolving credit facility (1)	92,540		12,411		24,891		24,891		24,891		5,456
Senior notes	108,063		8,313		16,625		16,625		16,625		49,875
Other long-term debt	1,090		273		388		211		118		100
Standby letters of credit	85,916		—		—		—		—		85,916
Future minimum lease payments under noncancelable operating leases	291,508		31,924		51,652		46,720		44,174		117,038
Fixed price commodity purchase commitments	74,356		74,356		—		—		—		—
Index priced commodity purchase commitments (2)	1,232,676		1,075,094		128,858		28,724		—		—
Total contractual obligations	$	2,800,444	$	1,208,151	$	229,327	$	120,357	$	87,696	$	1,154,913

Natural gas liquids gallons under fixed-price purchase commitments (thousands) (3)	79,041		79,041		—		—		—		—
Natural gas liquids gallons under index-price purchase commitments (thousands) (3)	653,808		593,952		59,856		—		—		—
Crude oil barrels under index-price purchase commitments (thousands) (3)	4,963		3,918		688		357		—		—

(1) The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at September 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 September 30, 2013. A theoretical change of $0.10 per gallon in the underlying commodity price at September 30, 2013 would result in a change of approximately $65.4 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 September 30, 2013 would result in a change of approximately $5.0 million in the value of our index-based crude oil purchase commitments.

(3) At September 30, 2013, we had fixed priced and index-price sales contracts for approximately 146.4 million and 464.2 million gallons of natural gas liquids, respectively. At September 30, 2013, we had index-price sales contracts for approximately 4.6 million barrels of crude oil.

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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 quarterly report.

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 oil in different locations can also fluctuate widely. If these price differences are high, we are able to generate higher margins by transporting crude oil from lower-price markets to higher-price markets. During the fiscal year ended March 31, 2013, the spread between crude oil prices in the mid-continent region and crude oil prices in south Texas widened, which gave us the opportunity to generate favorable margins by transporting crude oil from one region to the other. This spread narrowed considerably during the six months ended September 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 most of these regions. A future decline in the level of production could have an adverse impact on profitability.

During the three months ended September 30, 2013, we completed three separate acquisitions of water services businesses with operations in Texas. As a result, the geographic mix of our water services segment has changed, and we expect a greater share of the revenues from this segment to be generated from our operations in the Permian and Eagle Ford Basins than in the past.

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.

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Critical Accounting Policies

The preparation of financial statements and related disclosures in compliance with GAAP requires the selection and application of appropriate accounting principles to the relevant facts and circumstances of the Partnership’s operations and the use of estimates made by management. We have identified the following 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.

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. 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.

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 September 30, 2013, we have recorded a liability of $1.8 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.

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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. 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.

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.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

As of September 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 September 30, 2013, we had $646.0 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 $0.8 million.

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 oil marketing 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 September 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 and financial derivatives to reduce the effect of price volatility on our product costs, protect the value of our inventory positions, and to help ensure the availability of product during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes when we have a matching purchase commitment from our wholesale and retail customers. 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.

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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 September 30, 2013, the fair value of our unsettled commodity derivative instruments was a net liability of $5.9 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)	$	(3,186	)
Crude oil (water services segment)	(6,157		)
Crude oil (natural gas liquids logistics segment)	(6,079		)
Propane (natural gas liquids logistics segment)	(4,015		)
Other natural gas liquids (natural gas liquids logistics segment)	3,437
Heating oil (retail segment)	4

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, as amended (the “Exchange Act”)) that are designed to provide reasonable assurance that information required to be disclosed in our filings and submissions under the Exchange Act, 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 September 30, 2013. Based on this evaluation, our principal executive officer and principal financial officer have concluded that as of September 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 and the six months ended September 30, 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 September 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 and during the six months ended September 30, 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 fiscal quarters, 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 Contingencies” 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

During the three months ended September 30, 2013, we completed three acquisitions in which we issued unregistered common units as part of the consideration for the acquisitions. All of these units were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended, as the units were issued to the owners of businesses acquired in privately negotiated transactions not involving any public offering or solicitation. On July 1, 2013, we issued 175,211 common units to the sellers of Crescent Terminals, LLC and Cierra Marine, LP. On August 1, 2013, we issued 2,463,287 common units to the sellers of entities affiliated with Oilfield Water Lines, LP. On September 3, 2013, we issued 222,381 common units to the sellers of Coastal Plains Disposal #1, LLC.

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

2.1		LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL Pearsall SWD, LLC, OWL Pearsall Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.2		LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL Karnes SWD, LLC, OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.3		LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Cotulla SWD, LLC, Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.4		LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Nixon SWD, LLC, Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.5		LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, HR OWL, LLC, OWL Operating, LLC, Lotus Oilfield Services, L.L.C., OWL Lotus, LLC, NGL Energy Partners, LP, High Sierra Water-Eagle Ford, LLC and High Sierra Transportation, LLC (incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
3.1		Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as of August 6, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
4.1		Amendment No. 7 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of August 1, 2013, by and among NGL Energy Partners LLC, Oilfield Water Lines, LP and Terry G. Bailey (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
4.2		Amendment No. 3 to Note Purchase Agreement, dated September 30, 2013, among NGL Energy Partners LP and the holders of NGL’s 6.65% senior secured notes due 2022 signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013)
10.1		Amendment No. 3 to Credit Agreement, dated September 30, 2013, among NGL Energy Partners LP, NGL Energy Operating LLC, each subsidiary of NGL identified as a “Borrower” therein, Deutsche Bank AG, New York Branch, as technical agent, Deutsche Bank Trust Company Americas, as administrative agent and collateral agent and each financial institution identified as a “Lender” or “Issuing Bank” therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 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

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* 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 September 30, 2013 and March 31, 2013, (ii) Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2013 and 2012, (iii) Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and six months ended September 30, 2013 and 2012, (iv) Condensed Consolidated Statement of Changes in Partners’ Equity for the six months ended September 30, 2013, (v) Condensed Consolidated Statements of Cash Flows for the six months ended September 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: November 12, 2013		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer


Date: November 12, 2013		By:	/s/ Atanas H. Atanasov
			Atanas H. Atanasov
			Chief Financial Officer

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EXHIBIT INDEX

Exhibit Number		Exhibit

2.1		LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL Pearsall SWD, LLC, OWL Pearsall Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.2		LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL Karnes SWD, LLC, OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.3		LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Cotulla SWD, LLC, Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.4		LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Nixon SWD, LLC, Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.5		LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, HR OWL, LLC, OWL Operating, LLC, Lotus Oilfield Services, L.L.C., OWL Lotus, LLC, NGL Energy Partners, LP, High Sierra Water-Eagle Ford, LLC and High Sierra Transportation, LLC (incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
3.1		Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as of August 6, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
4.1		Amendment No. 7 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of August 1, 2013, by and among NGL Energy Partners LLC, Oilfield Water Lines, LP and Terry G. Bailey (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
4.2		Amendment No. 3 to Note Purchase Agreement, dated September 30, 2013, among NGL Energy Partners LP and the holders of NGL’s 6.65% senior secured notes due 2022 signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013)
10.1		Amendment No. 3 to Credit Agreement, dated September 30, 2013, among NGL Energy Partners LP, NGL Energy Operating LLC, each subsidiary of NGL identified as a “Borrower” therein, Deutsche Bank AG, New York Branch, as technical agent, Deutsche Bank Trust Company Americas, as administrative agent and collateral agent and each financial institution identified as a “Lender” or “Issuing Bank” therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 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

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* Exhibits filed with this report.