NGL Energy Partners LP - Quarter Report: 2013 December (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 December 31, 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		(I.R.S. Employer Identification No.)
Organization)

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

At February 3, 2014, there were 74,772,660 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 at December 31, 2013 and March 31, 2013	3
	Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2013 and 2012	4
	Condensed Consolidated Statements of Comprehensive Income for the three months and nine months ended December 31, 2013 and 2012	5
	Condensed Consolidated Statement of Changes in Partners’ Equity for the nine months ended December 31, 2013	6
	Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 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	41
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	73
Item 4.	Controls and Procedures	74

PART II

Item 1.	Legal Proceedings	75
Item 1A.	Risk Factors	75
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	76
Item 3.	Defaults Upon Senior Securities	76
Item 4.	Mine Safety Disclosures	76
Item 5.	Other Information	76
Item 6.	Exhibits	77

Signatures		79

Exhibit Index		80

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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 consolidated financial position and results of operations are:

· the prices for crude oil, natural gas, natural gas liquids, refined products, ethanol, and biodiesel;

· 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, natural gas liquids, refined products, ethanol, and biodiesel;

· the availability of supply of crude oil, natural gas liquids, refined products, ethanol, and biodiesel;

· 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 and distillates 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 crude oil, natural gas liquids, refined products, ethanol, and biodiesel;

· 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 car, 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 crude oil and natural gas liquids industries and competition from other marketers;

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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 and water disposal, recycle, and discharge 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 the financial condition and results of operations of entities in which we own noncontrolling equity interests;

· 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, natural gas liquids, refined products, ethanol, and biodiesel, our processing of wastewater, and transportation and risk management activities; and

· the costs and effects of legal and administrative proceedings;

· the demand for refined products;

· any reduction or elimination of the Renewable Fuels Standard;

· the operational and financial success of our joint venture; and

· changes in the jurisdictional characteristics of, or the applicable regulatory policies with respect to, our joint venture’s pipeline assets.

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

At December 31, 2013 and March 31, 2013

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

	December 31,			March 31,
	2013			2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	8,901		$	11,561
Accounts receivable - trade, net of allowance for doubtful accounts of $2,881 and $1,760, respectively	1,099,833			562,889
Accounts receivable - affiliates	6,375			22,883
Inventories	443,171			126,895
Prepaid expenses and other current assets	96,719			37,891
Total current assets	1,654,999			762,119

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $90,655 and $50,127, respectively	806,437			516,937
GOODWILL	1,037,237			563,146
INTANGIBLE ASSETS, net of accumulated amortization of $91,121 and $44,155, respectively	713,974			442,603
INVESTMENTS IN UNCONSOLIDATED ENTITIES	248,376			—
OTHER NONCURRENT ASSETS	15,955			6,542
Total assets	$	4,476,978		$	2,291,347

LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES:
Trade accounts payable	$	1,152,530		$	535,687
Accrued expenses and other payables	141,950			85,703
Advance payments received from customers	62,045			22,372
Accounts payable - affiliates	18,077			6,900
Current maturities of long-term debt	7,799			8,626
Total current liabilities	1,382,401			659,288

LONG-TERM DEBT, net of current maturities	1,517,519			740,436
OTHER NONCURRENT LIABILITIES	39,471			2,205

COMMITMENTS AND CONTINGENCIES

PARTNERS’ EQUITY, per accompanying statement:
General Partner — 0.1% interest; 79,406 and 53,676 notional units outstanding at December 31, 2013 and March 31, 2013, respectively	(46,781		)	(50,497		)
Limited Partners — 99.9% interest —
Common units — 73,407,732 and 47,703,313 units outstanding at December 31, 2013 and March 31, 2013, respectively	1,574,842			920,998
Subordinated units — 5,919,346 units outstanding at December 31, 2013 and March 31, 2013	2,444			13,153
Accumulated other comprehensive income (loss)	(106		)	24
Noncontrolling interests	7,188			5,740
Total partners’ equity	1,537,587			889,418
Total liabilities and partners’ equity	$	4,476,978		$	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 Nine Months Ended December 31, 2013 and 2012

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

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
REVENUES:
Crude oil logistics	$	1,316,060		$	677,985		$	3,260,862		$	1,462,523
Water solutions	41,772			22,806			96,475			40,557
Natural gas liquids logistics	800,917			508,131			1,646,750			1,050,116
Retail propane	161,537			127,905			293,134			244,116
Other	423,159			1,381			426,118			2,842
Total Revenues	2,743,445			1,338,208			5,723,339			2,800,154

COST OF SALES:
Crude oil logistics	1,300,911			654,976			3,202,265			1,425,546
Water solutions	2,571			1,499			6,936			4,169
Natural gas liquids logistics	745,894			470,621			1,555,539			982,949
Retail propane	105,394			77,449			181,956			144,556
Other	421,259			—			421,259			—
Total Cost of Sales	2,576,029			1,204,545			5,367,955			2,557,220

OPERATING COSTS AND EXPENSES:
Operating	69,261			50,518			174,075			113,287
General and administrative	21,492			14,175			54,258			34,578
Depreciation and amortization	35,494			18,747			83,279			41,335
Operating Income	41,169			50,223			43,772			53,734

OTHER INCOME (EXPENSE):
Interest expense	(16,745		)	(9,762		)	(38,427		)	(22,254		)
Loss on early extinguishment of debt	—			—			—			(5,769		)
Other, net	154			261			623			919
Income Before Income Taxes	24,578			40,722			5,968			26,630

INCOME TAX PROVISION	(526		)	(245		)	(356		)	(781		)

Net Income	24,052			40,477			5,612			25,849

Net Income Allocated to General Partner	(4,260		)	(942		)	(8,399		)	(1,731		)

Net Income Attributable to Noncontrolling Interests	(154		)	(301		)	(288		)	(250		)

Net Income (Loss) Allocated to Limited Partners	$	19,638		$	39,234		$	(3,075	)	$	23,868

Basic and Diluted Income (Loss) per Common Unit	$	0.27		$	0.75		$	(0.03	)	$	0.53

Basic and Diluted Income (Loss) per Subordinated Unit	$	0.23		$	0.75		$	(0.22	)	$	0.51

Basic and Diluted Weighted Average Units Outstanding:
Common	67,941,726			46,364,381			58,222,924			39,288,012
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

Three Months and Nine Months Ended December 31, 2013 and 2012

(U.S. Dollars in Thousands)

	Three Months Ended					Nine Months Ended
	December 31,					December 31,
	2013			2012		2013			2012

Net income	$	24,052		$	40,477	$	5,612		$	25,849
Other comprehensive income (loss), net of tax	(100		)	4		(130		)	1
Comprehensive income	$	23,952		$	40,481	$	5,482		$	25,850

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

Nine Months Ended December 31, 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	(5,419		)	—	(84,463		)	—	(8,775		)	—			(840		)	(99,497		)
Contributions	736			—	—			—	—			—			2,000			2,736
Sales of units, net of issuance costs	—			22,560,848	650,210			—	—			—			—			650,210
Units issued in business combinations, net of issuance costs	—			2,860,879	80,619			—	—			—			—			80,619
Equity issued pursuant to incentive compensation plan	—			282,692	8,619			—	—			—			—			8,619
Net income (loss)	8,399			—	(1,141		)	—	(1,934		)	—			288			5,612
Other comprehensive loss	—			—	—			—	—			(130		)	—			(130		)
BALANCES, DECEMBER 31, 2013	$	(46,781	)	73,407,732	$	1,574,842		5,919,346	$	2,444		$	(106	)	$	7,188		$	1,537,587

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

Nine Months Ended December 31, 2013 and 2012

(U.S. Dollars in Thousands)

	Nine Months Ended
	December 31,
	2013			2012
OPERATING ACTIVITIES:
Net income	$	5,612		$	25,849
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization, including debt issuance cost amortization	89,851			46,911
Loss on early extinguishment of debt	—			5,769
Non-cash equity-based compensation expense	10,840			5,322
Loss (gain) on disposal of assets	2,503			(34		)
Provision for doubtful accounts	2,112			909
Commodity derivative (gain) loss	26,711			(12,024		)
Other	(318		)	(13		)
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable - trade	(160,037		)	(29,287		)
Accounts receivable - affiliates	19,072			8,672
Inventories	(165,116		)	(88,631		)
Prepaid expenses and other current assets	(5,811		)	6,814
Trade accounts payable	204,302			26,437
Accrued expenses and other payables	(2,143		)	(12,482		)
Accounts payable - affiliates	8,592			(11,951		)
Advance payments received from customers	29,006			25,813
Net cash provided by (used in) operating activities	65,176			(1,926		)

INVESTING ACTIVITIES:
Purchases of long-lived assets	(107,945		)	(37,369		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	(1,240,578		)	(493,296		)
Cash flows from commodity derivatives	(30,659		)	14,478
Proceeds from sales of assets	7,302			700
Investments in unconsolidated entities	(2,000		)	—
Distributions of capital from unconsolidated entities	1,591			—
Other	(102		)	645
Net cash used in investing activities	(1,372,391		)	(514,842		)

FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	2,040,500			977,975
Payments on revolving credit facilities	(1,709,500		)	(628,975		)
Issuances of notes	450,000			250,000
Proceeds from borrowings on other long-term debt	880			—
Payments on other long-term debt	(6,713		)	(1,346		)
Debt issuance costs	(24,061		)	(18,613		)
Contributions	2,736			876
Distributions	(99,497		)	(46,436		)
Proceeds from sale of common units, net of offering costs	650,210			(642		)
Net cash provided by financing activities	1,304,555			532,839
Net increase (decrease) in cash and cash equivalents	(2,660		)	16,071
Cash and cash equivalents, beginning of period	11,561			7,832
Cash and cash equivalents, end of period	$	8,901		$	23,903

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

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

Note 1 — Organization and Operations

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.

At December 31, 2013, our primary 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, and a 50% interest in a crude oil pipeline. 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 solutions business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks. Our water solutions business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from crude oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons.

· Our 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 22 terminals throughout the United States and rail car transportation services through its fleet of leased and owned rail cars. Our natural gas liquids logistics business 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 nine months ended December 31, 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 at 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 (“GAAP”) for interim consolidated financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. The unaudited condensed consolidated financial statements include all adjustments that 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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

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.

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.

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

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 described 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 December 31, 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

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

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 December 31, 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 hierarchy. Assessing the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability.

Supplemental Cash Flow Information

Supplemental cash flow information is as follows:

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2013		2012		2013		2012
	(in thousands)

Interest paid, exclusive of debt issuance costs	$	6,821	$	9,426	$	23,729	$	19,257
Income taxes paid	$	475	$	560	$	1,125	$	736

Value of common units issued in business combinations	$	—	$	57,259	$	80,619	$	490,927

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:

	December 31,		March 31,
	2013		2013
	(in thousands)
Crude oil	$	125,313	$	46,156
Natural gas liquids:
Propane	148,604		45,428
Butane	45,673		23,106
Other	13,743		984
Fuels (*)	77,854		—
Natural gas	17,389		—
Other	14,595		11,221
	$	443,171	$	126,895

(*) Primarily includes gasoline, diesel, biodiesel, and ethanol.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

Investments in Unconsolidated Entities

As part of the December 2013 acquisition of Gavilon, LLC (“Gavilon Energy”), we acquired a 50% interest in Glass Mountain Pipeline, LLC (“Glass Mountain”). We account for our interest in Glass Mountain under the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of Glass Mountain on our consolidated balance sheet. Instead, our ownership interest is reflected in one line as a noncurrent asset on our consolidated balance sheet. We will record our share of any income or loss generated by Glass Mountain as in increase to our equity method investment, and will record any distributions we receive from Glass Mountain as a reduction to our equity method investment. In addition, as part of the December 2013 acquisition of Gavilon Energy, we acquired an 11% interest in a limited liability company that owns an ethanol production facility in Nebraska.

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following:

	December 31,		March 31,
	2013		2013
	(in thousands)

Product exchange liabilities	$	19,136	$	6,741
Income and other tax liabilities	13,853		22,659
Accrued compensation and benefits	52,541		27,252
Other	56,420		29,051
	$	141,950	$	85,703

Water Facility Development Agreement

In connection with one of our business combinations, we entered into a development agreement whereby we may acquire additional water disposal facilities in Texas. Under this agreement, the other party (the “Developer”) may develop facilities in a designated area. We then have the option to operate the facility for a period of up to ninety days, during which time we may elect to purchase the facility. If we elect to purchase the facility, the Developer may choose one of two options specified in the agreement for the calculation of the purchase price.

During the period between which we have begun operating the facility and before we have decided whether to purchase the facility, we are entitled to a fee for operating the facility, which is forfeitable if we elect not to purchase the facility. We will recognize revenue for these operator fees once they cease to be forfeitable. If we elect to purchase a facility, we will account for the transaction as a business combination at the date the purchase is completed.

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 nine months ended December 31, 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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

Also as described in Note 3, we made certain adjustments during the nine months ended December 31, 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 retrospectively 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

Gavilon Energy

On December 2, 2013, we completed a business combination with Gavilon Energy. We paid $832.4 million of cash, net of cash acquired, in exchange for these assets and operations. The acquisition agreement also contemplates a post-closing adjustment to the purchase price for certain working capital items. We incurred and charged to general and administrative expense during the three months ended December 31, 2013 $5.0 million of costs related to the acquisition of Gavilon Energy.

The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas, and Louisiana and a 50% interest in Glass Mountain, which owns a crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma. Glass Mountain became operational in February 2014. The operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, natural gas liquids, and natural gas.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in the acquisition of Gavilon Energy. The estimates of fair value reflected at December 31, 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 September 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	367,568
Accounts receivable - affiliates	2,564
Inventories	148,782
Prepaid expenses and other current assets	64,203
Property, plant and equipment:
Crude oil tanks and related equipment (5 — 40 years)	106,855
Vehicles (3 years)	58
Information technology equipment (3 — 7 years)	7,939
Buildings and leasehold improvements (3 — 40 years)	190
Land	6,240
Other (7 years)	7,327
Goodwill	283,216
Intangible assets:
Customer relationships (10 — 20 years)	104,000
Investments in unconsolidated entities	248,000
Other noncurrent assets	9,918
Trade accounts payable	(404,955		)
Accrued expenses and other payables	(67,545		)
Advance payments received from customers	(10,667		)
Accounts payable - affiliates	(2,585		)
Other noncurrent liabilities	(38,660		)
Fair value of net assets acquired	$	832,448

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

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

The operations of Gavilon Energy have been included in our consolidated statement of operations since Gavilon Energy was acquired on December 2, 2013. Our consolidated statements of operations for the three months and nine months ended December 31, 2013 include revenues of $902.9 million that were generated by the operations of Gavilon Energy. The following unaudited pro forma consolidated data below is presented as if the Gavilon Energy acquisition had been completed on April 1, 2012 (in thousands, except per unit amounts). The pro forma earnings per unit are based on the common and subordinated units outstanding at December 31, 2013.

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2013		2012		2013			2012

Revenues	$	4,601,990	$	6,429,946	$	17,115,115		$	16,419,955
Net income (loss) from continuing operations	21,397		26,910		763			(43,825		)
Limited partners’ interest in income (loss) from continuing operations	16,983		25,653		(7,924		)	(45,876		)
Basic and diluted earnings (loss) from continuing operations per common unit	$	0.21	$	0.32	$	(0.10	)	$	(0.58	)
Basic and diluted earnings (loss) from continuing operations per subordinated unit	$	0.21	$	0.32	$	(0.10	)	$	(0.58	)

The pro forma consolidated data in the table above was prepared by adding the historical results of operations of Gavilon Energy 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 Gavilon Energy 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 Gavilon Energy 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 December 31, 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, 2012, nor is it necessarily indicative of the future results of the combined operations. Gavilon Energy historically conducted trading operations. The data in the table above does not give pro forma effect to the fact that it is now a logistics business.

Oilfield Water Lines, LP

On August 2, 2013, we completed a business combination with entities affiliated with Oilfield Water Lines, LP (collectively, “OWL”), whereby we acquired water disposal and transportation assets in Texas. We issued 2,463,287 common units, valued at $68.6 million, and paid $167.7 million of cash, net of cash acquired, in exchange for OWL. 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 $60.0 million. We incurred and charged to general and administrative expense during the nine months ended December 31, 2013 $0.8 million of costs related to the OWL acquisition.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in the acquisition of OWL. The estimates of fair value reflected at December 31, 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):

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

Accounts receivable - trade	$	7,142
Inventories	154
Other current assets	402
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)	110,000
Non-compete agreements (2.5 years)	230
Goodwill	91,360
Trade accounts payable	(6,406		)
Accrued expenses	(992		)
Other noncurrent liabilities	(64		)
Fair value of net assets acquired	$	236,289

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	167,720
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 assumed. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

As 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 similar calculations at September 30, 2013 and December 31, 2013, and concluded that the fair value of the contingent consideration continued to approximate zero at those dates. During the fourth quarter of our fiscal year, we will finalize the calculation of performance relative to the target. If any contingent consideration is required to be paid, we will record such payment as an expense during the fourth quarter of our fiscal year.

The operations of OWL have been included in our consolidated statement of operations since OWL was acquired on August 2, 2013. Our consolidated statement of operations for the nine months ended December 31, 2013 includes revenues of $18.0 million and an operating loss of $6.5 million that was generated by the operations of OWL.

The following unaudited pro forma consolidated data below is presented for the nine months ended December 31, 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 at December 31, 2013.

Revenues	$	5,735,381
Net loss	(9,656		)
Limited partners’ interest in net loss	(18,343		)
Basic and diluted loss per common unit	(0.23		)
Basic and diluted loss per subordinated unit	(0.23		)

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

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 December 31, 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 were developed after April 1, 2012.

Other Water Solutions 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 $151.3 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. The agreement for one of these acquisitions contemplates a post-closing payment for certain working capital items. Our consolidated statement of operations for the nine months ended December 31, 2013 includes revenues of $11.3 million and operating income of $3.6 million that was generated by the operations of these two acquisitions. We incurred and charged to general and administrative expense during the nine months ended December 31, 2013 $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 at December 31, 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)	56,750
Trade names (indefinite life)	2,800
Non-compete agreements (3 years)	260
Water facility development agreement (5 years)	14,000
Water facility option agreement	2,500
Goodwill	63,370
Trade accounts payable	(82		)
Accrued expenses	(273		)
Other noncurrent liabilities	(64		)
Fair value of net assets acquired	$	158,131

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	151,337
Value of common units issued	6,794
Total consideration paid	$	158,131

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

As part of one of these business combinations, we entered into an option agreement with the seller of the business whereby we had the option to purchase a salt water disposal facility that was under construction. We recorded an intangible asset of $2.5 million at the acquisition date related to this option agreement.

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 nine months ended December 31, 2013 $0.2 million of costs related to these acquisitions.

Accounts receivable - trade	$	1,235
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)	3,450
Barges and tow boats (20 years)	20,835
Other (3-5 years)	42
Intangible assets:
Customer relationships (3 years)	1,700
Non-compete agreement (3 years)	35
Trade names (indefinite life)	530
Goodwill	42,115
Trade accounts payable	(665		)
Accrued expenses	(124		)
Other noncurrent liabilities	(53		)
Fair value of net assets acquired	$	73,090

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

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

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

Retail Propane and Natural Gas Liquids Logistics Acquisitions

During the nine months ended December 31, 2013, we completed four acquisitions of retail propane businesses and the acquisition of four natural gas liquids terminals. On a combined basis, we paid $21.2 million of cash to acquire these assets and operations. The agreements for certain of these acquisitions contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in certain of these business combinations, and as a result the estimates of fair value reflected at December 31, 2013 are subject to change.

Fiscal Year Ended March 31, 2013

Pecos Combination

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

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:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

				Estimated
				at
				March 31,
	Final			2013			Change
	(in thousands)
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

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

Third Coast Combination

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

During the three months ended December 31, 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 their useful lives) and liabilities assumed in the acquisition of Third Coast:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

				Estimated
				at
				March 31,
	Final			2013			Change
	(in thousands)
Accounts receivable - trade	$	2,195		$	2,248		$	(53	)
Inventories	140			140			—
Property, plant and equipment:
Barges and tow boats (20 years)	17,711			12,883			4,828
Other	—			30			(30		)
Intangible assets:
Customer relationships (3 years)	3,000			4,000			(1,000		)
Trade names (indefinite life)	850			500			350
Goodwill	18,847			22,551			(3,704		)
Other noncurrent assets	2,733			2,733			—
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

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

Other Crude Oil Logistics and Water Solutions Business Combinations

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

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:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

				Estimated
				at
				March 31,
	Final			2013			Change
	(in thousands)
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

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

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

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

Note 4 — Earnings per Unit

Our earnings per common and subordinated unit were computed as follows:

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
	(in thousands, except unit and per unit amounts)

Income attributable to parent equity	$	23,898		$	40,176		$	5,324		$	25,599
Income allocated to general partner(*)	(4,260		)	(942		)	(8,399		)	(1,731		)
Income allocated to limited partners	$	19,638		$	39,234		$	(3,075	)	$	23,868

Income allocated to:
Common unitholders	$	18,285		$	34,799		$	(1,780	)	$	20,843
Subordinated unitholders	$	1,353		$	4,435		$	(1,295	)	$	3,025

Weighted average common units outstanding	67,941,726			46,364,381			58,222,924			39,288,012

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

Income per common unit - basic and diluted	$	0.27		$	0.75		$	(0.03	)	$	0.53

Income (loss) per subordinated unit - basic and diluted	$	0.23		$	0.75		$	(0.22	)	$	0.51

(*) 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 months and nine months ended December 31, 2013 and 2012.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

Note 5 — Property, Plant and Equipment

Our property, plant and equipment consists of the following:

	December 31,			March 31,
	2013			2013
	(in thousands)
Description and Useful Life
Natural gas liquids terminal assets (30 years)	$	76,656		$	63,637
Retail propane equipment (5-20 years)	159,523			152,802
Vehicles (5-10 years)	109,029			85,200
Water treatment facilities and equipment (3-30 years)	168,133			91,601
Crude oil tanks and related equipment (2-30 years)	135,422			21,308
Barges and tow boats (20 years)	51,452			21,135
Information technology equipment (3-5 years)	23,971			12,169
Buildings and leasehold improvements (5-30 years)	46,189			48,394
Land	29,894			21,604
Other (3-10 years)	17,971			17,288
Construction in progress	78,852			31,926
	897,092			567,064
Less: Accumulated depreciation	(90,655		)	(50,127		)
Net property, plant and equipment	$	806,437		$	516,937

Depreciation expense was $15.6 million and $9.2 million during the three months ended December 31, 2013 and 2012, respectively, and $42.8 million and $23.0 million during the nine months ended December 31, 2013 and 2012, respectively.

Note 6 — Goodwill and Intangible Assets

The changes in the balance of goodwill during the nine months ended December 31, 2013 were as follows (in thousands):

Balance at March 31, 2013	$	563,146
Revisions to acquisition accounting (Note 3)	(7,886		)
Acquisitions	481,977
Balance at December 31, 2013	$	1,037,237

Goodwill by reportable segment is as follows:

	December 31,		March 31,
	2013		2013
	(in thousands)
Crude oil logistics	$	571,675	$	244,073
Water solutions	264,203		119,668
Natural gas liquids logistics	87,136		87,136
Retail propane	114,223		112,269
	$	1,037,237	$	563,146

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

Our intangible assets consist of the following:

		December 31, 2013				March 31, 2013
		Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Useful Lives	Amount		Amortization		Amount		Amortization
		(in thousands)
Amortizable —
Customer relationships*	3-20 years	$	679,845	$	67,468	$	407,835	$	30,959
Water facility development agreement	5 years	14,000		1,400		—		—
Lease and other agreements	1-8 years	15,220		9,540		15,210		7,018
Non-compete agreements	2-7 years	12,391		5,135		11,855		2,871
Trade names	3-10 years	2,784		550		2,784		326
Debt issuance costs	5-10 years	43,555		7,028		19,494		2,981
Total amortizable		767,795		91,121		457,178		44,155

Non-amortizable —
Trade names		34,800		—		29,580		—
Water facility option agreement		2,500		—		—		—
Total		$	805,095	$	91,121	$	486,758	$	44,155

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

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

Year Ending March 31,
2014 (three months)	$	21,680
2015	84,490
2016	82,391
2017	79,292
2018	76,669
Thereafter	332,152
	$	676,674

Amortization expense was as follows:

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2013		2012		2013		2012
	(in thousands)
Recorded in
Depreciation and amortization	$	19,888	$	9,474	$	40,488	$	18,294
Cost of sales	943		1,763		2,517		3,315
Interest expense	1,593		925		4,055		2,261
Loss on early extinguishment of debt	—		—		—		5,769
	$	22,424	$	12,162	$	47,060	$	29,639

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

Note 7 — Long-Term Debt

Our long-term debt consists of the following:

	December 31,		March 31,
	2013		2013
	(in thousands)
Revolving credit facility —
Expansion capital loans	$	460,000	$	441,500
Working capital loans	348,500		36,000
Senior notes	250,000		250,000
Unsecured notes	450,000		—
Other notes payable	16,818		21,562
	1,525,318		749,062
Less - current maturities	7,799		8,626
Long-term debt	$	1,517,519	$	740,436

Credit Agreement

On June 19, 2012, we entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”).

The Working Capital Facility had a total capacity of $935.5 million for cash borrowings and letters of credit at December 31, 2013. At December 31, 2013, we had outstanding cash borrowings of $348.5 million and outstanding letters of credit of $387.4 million on the Working Capital Facility, leaving a remaining capacity of $199.6 million at December 31, 2013. The Expansion Capital Facility had a total capacity of $785.5 million for cash borrowings at December 31, 2013. At December 31, 2013, we had outstanding cash borrowings of $460.0 million on the Expansion Capital Facility, leaving a remaining capacity of $325.5 million at December 31, 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 December 31, 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 November 5, 2018. We have the right to pre-pay outstanding borrowings under the Credit Agreement without incurring any penalties, and pre-payments of principal may be required if we enter into certain transactions to sell assets or obtain new borrowings.

All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 0.50% to 1.50% per annum or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At December 31, 2013, the interest rate in effect on outstanding LIBOR borrowings was 1.92%, calculated as the LIBOR rate of 0.17% plus a margin of 1.75%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. At December 31, 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	$	460,000	1.92	%
Working Capital Facility —
LIBOR borrowings	348,500		1.92	%

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

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 December 31, 2013, our leverage ratio was approximately 3 to 1. The Credit Agreement also specifies that our “interest coverage ratio,” as defined in the Credit Agreement, cannot be less than 2.75 to 1 as of the last day of any fiscal quarter. At December 31, 2013, our interest coverage ratio was approximately 9 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 December 31, 2013, we were in compliance with all covenants under the Credit Agreement.

Senior Notes

On June 19, 2012, we entered into a note purchase agreement (as amended, the “Note Purchase Agreement”) whereby we issued $250.0 million of Senior Notes in a private placement (the “Senior Notes”). The Senior Notes have an aggregate principal amount of $250.0 million and bear interest at a fixed rate of 6.65%. Interest is payable quarterly. The Senior Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to pre-pay outstanding principal, although we would incur a pre-payment penalty. The Senior Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

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

The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary grace and cure periods): (i) non-payment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the Senior Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the Note Purchase Agreement, the Senior Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregate principal amount of the then outstanding Senior Notes of any series may declare all of the Senior Notes of such series to be due and payable immediately.

At December 31, 2013, we were in compliance with all covenants under the Note Purchase Agreement and the Senior Notes.

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 $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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

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.

Other Notes Payable

We have executed various non-interest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also have certain notes payable related to equipment financing, which have interest rates ranging from 2.06% to 4.92% at December 31, 2013.

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at December 31, 2013:

	Revolving						Other
	Credit		Senior		Unsecured		Notes
Year Ending March 31,	Facility		Notes		Notes		Payable		Total
	(in thousands)
2014 (three months)	$	—	$	—	$	—	$	2,100	$	2,100
2015	—		—		—		6,924		6,924
2016	—		—		—		3,669		3,669
2017	—		—		—		2,315		2,315
2018	—		25,000		—		1,418		26,418
Thereafter	808,500		225,000		450,000		392		1,483,892
	$	808,500	$	250,000	$	450,000	$	16,818	$	1,525,318

Previous Credit Facilities

On June 19, 2012, we made a principal payment of $306.8 million to retire our previous revolving credit facility. Upon retirement of this facility, we wrote off the portion of the debt issuance cost asset that had not yet been amortized. This expense is reported as “Loss on early extinguishment of debt” in our consolidated statement of operations for the nine months ended December 31, 2012.

Note 8 — Income Taxes

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

We have three taxable corporate subsidiaries in the United States and four taxable corporate subsidiaries in Canada. The income tax provision reported in our consolidated statements of operations relates in part to these subsidiaries. In addition, our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales.

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

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

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 December 31, 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 $3.3 million for services performed by us during the period from June 2013 through August 2013, pending resolution of the dispute, although the customer has not disputed the validity of the amounts billed for services performed during this time frame. Upon receiving this notification, we ceased providing services under this contract, and on November 5, 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. We are not able to reliably predict the outcome of this dispute at this time, but we do not believe the outcome will have a material adverse effect on our consolidated financial position or results of operations.

Canadian Fuel and Sales Taxes

The taxing authority of a province in Canada completed an audit of fuel and sales tax payments and alleged that an entity we acquired should have collected from customers and remitted to the taxing authority fuel taxes and sales taxes on certain historical sales. We recorded in the acquisition accounting a liability of $0.8 million (net of receivables for expected recoveries from other parties). We now believe this matter is substantially resolved, and we removed the liability from our consolidated balance sheet and recorded a corresponding reduction to cost of sales during the three months ended December 31, 2013.

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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

Asset Retirement Obligations

We have recorded an asset retirement obligation liability of $2.1 million at December 31, 2013. This liability is related to 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 at December 31, 2013 are as follows (in thousands):

Year Ending March 31,
2014 (three months)	$	39,151
2015	134,876
2016	110,868
2017	73,341
2018	59,378
Thereafter	127,497
Total	$	545,111

Rental expense relating to operating leases was $23.3 million during the three months ended December 31, 2013 and $15.9 million during the three months ended December 31, 2012. Rental expense relating to operating leases was $68.8 million during the nine months ended December 31, 2013 and $38.1 million during the nine months ended December 31, 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 December 31, 2013, we had the following such commitments outstanding:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

	Volume	Value
	(in thousands)
Natural gas liquids fixed-price purchase commitments (gallons)	30,302	$	42,720
Natural gas liquids floating-price purchase commitments (gallons)	399,234	506,931
Natural gas liquids fixed-price sale commitments (gallons)	84,388	106,812
Natural gas liquids floating-price sale commitments (gallons)	324,114	433,875
Crude oil floating-price purchase commitments (barrels)	4,773	497,598
Crude oil floating-price sale commitments (barrels)	6,081	650,447

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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

Note 10 — Equity

Partnership Equity

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

The subordination period will end on the first business day after we have earned and paid the minimum quarterly distribution on each outstanding common unit and subordinated unit and the corresponding distribution on the general partner interest for each of three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2014. 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 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.”

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

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	%

On January 23, 2014, we declared a distribution of $0.53125 per common unit, to be paid on February 14, 2014 to unitholders of record on February 4, 2014. This distribution amounts to $46.4 million, including amounts to be paid on common, subordinated, and general partner notional units and the amount to be paid on incentive distribution rights.

Equity Issuances

On July 5, 2013, we completed a public offering of 10,350,000 common units. We received net proceeds of $287.5 million, after underwriting discounts and commissions of $12.0 million and offering costs of $0.7 million.

On September 25, 2013, we completed a public offering of 4,100,000 common units. We received net proceeds of $127.7 million, after underwriting discounts and commissions of $5.0 million and offering costs of $0.1 million.

On December 2, 2013, we issued and sold 8,110,848 of our common units in a private placement. We received net proceeds of $235.1 million, after offering costs of $4.9 million. The agreement for the sale will require us to register these units for resale under the Securities Act on or before February 28, 2014.

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. The board of directors of our general partner has granted certain restricted units to employees and directors, which will vest in tranches, subject to the continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

The following table summarizes the restricted unit activity during the nine months ended December 31, 2013:

Unvested restricted units at March 31, 2013	1,444,900
Units granted	331,500
Units vested and issued	(282,692	)
Units withheld for employee taxes	(116,108	)
Units forfeited	(15,000	)
Unvested restricted units at December 31, 2013	1,362,600

The scheduled vesting of the awards is summarized below:

Vesting Date		Number of Awards
January 1, 2014		20,000
July 1, 2014		400,800
January 1, 2015		12,000
July 1, 2015		323,800
January 1, 2016		12,000
July 1, 2016		315,000
January 1, 2017		12,000
July 1, 2017		220,500
January 1, 2018		12,000
July 1, 2018		34,500
Total unvested units at December 31, 2013		1,362,600

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.

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 (in thousands):

Three Months Ended:
December 31, 2013	$	4,078
December 31, 2012	2,365

Nine Months Ended:
December 31, 2013	$	14,370
December 31, 2012	5,322

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

We estimate that the future expense we will record on the unvested awards at December 31, 2013 will be as follows (in thousands), after taking into consideration an estimate of forfeitures of 64,000 units. For purposes of this calculation, we have used the closing price of the common units on December 31, 2013, which was $34.50.

Year Ending March 31,
2014 (three months)	$	3,589
2015	11,931
2016	10,734
2017	8,186
2018	2,836
2019	267
Total	$	37,543

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 nine months ended December 31, 2013	14,370
Value of units vested and issued	(8,619		)
Taxes paid on behalf of participants	(3,530		)
Balance at December 31, 2013	$	7,264

The weighted-average fair value of the awards at December 31, 2013 was $30.19, which was calculated as the closing price of the common units on December 31, 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. At December 31, 2013, 6.1 million units remain available for issuance under the LTIP.

Note 11 — Fair Value of Financial Instruments

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

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

Commodity Derivatives

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

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	1,032		$	(8,381	)
Level 2 measurements	41,433			(29,878		)
	42,465			(38,259		)

Netting of counterparty contracts (1)	(8,835		)	8,835
Cash collateral provided	—			8,581
Commodity contracts reported on consolidated balance sheet	$	33,630		$	(20,843	)

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

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

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

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

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

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

	December 31,			March 31,
	2013			2013
	(in thousands)
Prepaid expenses and other current assets	$	33,341		$	5,551
Other noncurrent assets	289			44
Accrued expenses and other payables	(20,728		)	(12,701		)
Other noncurrent liabilities	(115		)	—
Net asset (liability)	$	12,787		$	(7,106	)

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

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

		Total
		Notional		Fair Value of
		Units		Net Assets
Contracts	Settlement Period	(Barrels)		(Liabilities)
		(In thousands)
At December 31, 2013 -
Cross-commodity (1)	January 2014 - March 2015	125		$	(2,984	)
Crude oil fixed-price (2)	January 2014 - September 2014	(926	)	8,776
Crude oil index (3)	January 2014 - June 2014	1,273		285
Propane fixed-price (4)	January 2014 - March 2015	(236	)	1,715
Refined products fixed-price (5)	January 2014 - April 2014	113		829
Butane fixed-price (6)	January 2014 - April 2014	106		425
Natural gas fixed-price (7)	January 2014 - October 2016	(36	)	(4,891		)
Other	January 2014 - March 2014	10		51
				4,206
Net cash collateral provided				8,581
Net value of commodity derivatives on the consolidated balance sheet				$	12,787

At March 31, 2013 -
Cross-commodity(1)	April 2013 - March 2014	430		$	(10,208	)
Crude oil fixed-price (2)	April 2013 - March 2014	(144	)	1,033
Crude oil index (3)	April 2013 - June 2014	(91	)	153
Propane fixed-price (4)	April 2013 - March 2014	(282	)	3,197
Other	May 2013 - June 2013	8		79
				(5,746		)
Net cash collateral held				(1,360		)
Net value of commodity derivatives on the consolidated balance sheet				$	(7,106	)

(1) Cross-commodity — Our operating segments may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. The contracts listed in the table above as “Cross-commodity” represent financial derivatives we have entered into as an economic hedge against the risk of one commodity price moving relative to another commodity price.

(2) Crude oil fixed-price — Our crude oil 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 inventory.

(3) Crude oil index — Our crude oil segment may purchase or sell crude oil where the underlying contract pricing mechanisms are tied to different crude oil indices. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. The contract listed in the table above as “Crude oil index” represent financial derivatives we have entered into as an economic hedge against the risk of one crude oil index moving relative to another crude oil index.

(4) Propane fixed-price — Our natural gas liquids logistics segment routinely purchases inventory during the warmer months and stores the inventory for sale in the colder months. The contracts listed in this table as “Propane fixed-price” represent financial derivatives we have entered into as an economic hedge against the risk that propane prices will decline while we are holding the inventory.

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

(6) 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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

(7) Natural gas fixed-price — Our natural gas liquids logistics segment routinely purchases inventory during the warmer months and stores the inventory for sale in the colder months. The contracts listed in this table as “Natural gas fixed-price” represent financial derivatives we have entered into as an economic hedge against the risk that natural gas prices will decline while we are holding the inventory.

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

Three Months Ended:
December 31, 2013	$	(8,830	)
December 31, 2012	7,005

Nine Months Ended:
December 31, 2013	$	(26,711	)
December 31, 2012	12,024

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.

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

Interest Rate Risk

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At December 31, 2013, we had $808.5 million of outstanding borrowings under our Revolving Credit Facility at a rate of 1.92%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.0 million.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

Note 12 — Segments

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

Our crude oil logistics segment sells crude oil and provides crude oil transportation services to wholesalers, refiners, and producers. Our water solutions segment provides services for the 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 the refined products, ethanol, biodiesel, and natural gas marketing operations that we acquired in our December 2013 acquisition of Gavilon Energy. The “corporate and other” category also includes certain corporate expenses that are incurred and are not allocated to the reportable segments. This data is included to reconcile the data for the reportable segments to data in our consolidated financial statements.

Certain information related to the results of operations of each segment is shown in the tables below:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
	(in thousands)
Revenues:
Crude oil logistics -
Crude oil sales	$	1,319,290		$	683,054		$	3,260,885		$	1,468,731
Other revenues	6,198			1,174			25,927			3,708
Water solutions -
Water treatment and disposal	36,282			20,563			83,793			34,799
Water transportation	5,490			2,243			12,682			5,758
Natural gas liquids logistics -
Propane sales	518,541			255,157			833,815			477,981
Other product sales	336,654			286,598			895,113			626,360
Other revenues	7,695			8,822			25,809			17,143
Retail propane -
Propane sales	112,570			84,258			199,912			162,049
Distillate sales	37,648			33,062			66,079			55,685
Other revenues	11,377			10,585			27,275			26,382
Corporate and other	423,159			1,381			426,118			2,842
Elimination of intersegment sales	(71,459		)	(48,689		)	(134,069		)	(81,284		)
Total revenues	$	2,743,445		$	1,338,208		$	5,723,339		$	2,800,154

Depreciation and amortization:
Crude oil logistics	$	5,827		$	1,904		$	13,841		$	3,844
Water solutions	18,258			7,235			37,052			10,285
Natural gas liquids logistics	2,759			2,265			8,135			7,715
Retail propane	7,344			6,987			21,455			18,915
Corporate and other	1,306			356			2,796			576
Total depreciation and amortization	$	35,494		$	18,747		$	83,279		$	41,335

Operating income (loss):
Crude oil logistics	$	(6,424	)	$	11,407		$	6,069		$	17,226
Water solutions	982			5,499			6,938			10,046
Natural gas liquids logistics	40,601			25,090			53,091			36,492
Retail propane	21,696			16,437			15,672			9,797
Corporate and other	(15,686		)	(8,210		)	(37,998		)	(19,827		)
Total operating income	$	41,169		$	50,223		$	43,772		$	53,734

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

The table below shows additions to property, plant and equipment for each segment. This information has been prepared on the accrual basis, and includes property, plant and equipment acquired in acquisitions.

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2013		2012		2013		2012
	(in thousands)
Additions to property, plant and equipment, including acquisitions (accrual basis):
Crude oil logistics	$	153,209	$	53,913	$	188,671	$	82,227
Water solutions	11,533		34,227		81,715		130,584
Natural gas liquids logistics	21,267		8,452		49,583		13,896
Retail propane	8,915		9,816		20,407		67,063
Corporate and other	271		3,799		1,117		17,156
Total	$	195,195	$	110,207	$	341,493	$	310,926

The following tables show long-lived assets (consisting of property, plant and equipment, intangible assets, and goodwill) and total assets by segment:

	December 31,		March 31,
	2013		2013
	(in thousands)
Total assets:
Crude oil logistics	$	1,888,885	$	801,030
Water solutions	862,633		466,462
Natural gas liquids logistics	767,493		474,141
Retail propane	529,671		513,301
Corporate and other	428,296		36,413
Total	$	4,476,978	$	2,291,347

Long-lived assets, net:
Crude oil logistics	$	907,799	$	356,750
Water solutions	835,216		453,986
Natural gas liquids logistics	276,574		238,192
Retail propane	442,276		441,762
Corporate and other	95,783		31,996
Total	$	2,557,648	$	1,522,686

Note 13 — Transactions with Affiliates

SemGroup Corporation (“SemGroup”) holds 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 product to and purchased products and services from affiliates of SemGroup. Most of these transactions are included within revenues and cost of sales in our consolidated statements of operations.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2013 and March 31, 2013, and for the

Three Months and Nine Months Ended December 31, 2013 and 2012

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 $6.2 million of these transactions during the nine months ended December 31, 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:

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2013		2012		2013		2012
	(in thousands)
Sales to SemGroup	$	50,742	$	8,091	$	54,522	$	32,371
Purchases from SemGroup	73,731		16,744		121,647		43,821
Sales to entities affiliated with management	344		—		110,216		1,316
Purchases from entities affiliated with management	46,918		2,507		103,264		10,434

Receivables from affiliates consist of the following:

	December 31,		March 31,
	2013		2013
	(in thousands)
Receivables from entities affiliated with management	$	603	$	22,883
Receivables from SemGroup	5,772		—
	$	6,375	$	22,883

Payables to related parties consist of the following:

	December 31,		March 31,
	2013		2013
	(in thousands)
Payables to SemGroup	$	15,554	$	4,601
Payables to entities affiliated with management	2,523		2,299
	$	18,077	$	6,900

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

During the nine months ended December 31, 2013, we completed the acquisition of a crude oil logistics business owned by an employee. We paid $11.0 million of cash for this acquisition.

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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 nine months ended December 31, 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

At December 31, 2013, our primary businesses include:

Acquisitions of businesses during the current and prior fiscal year have had a significant impact on comparability of our results of operations. Our crude oil logistics business began with our June 2012 merger with High Sierra, and was subsequently expanded through the acquisitions of entities affiliated with Pecos Gathering & Marketing, L.L.C. (collectively, “Pecos”) in November 2012, Third Coast Towing, LLC (“Third Coast”) in December 2012, Cierra Marine, LP (“Cierra Marine”) and the assets of Crescent Terminals, LLC (“Crescent”) in July 2013, and Gavilon, LLC (“Gavilon Energy”) in December 2013. Our water solutions business also began with our June 2012 merger with High Sierra, and was subsequently expanded through the acquisitions of a water services business in Texas in October 2013 (“Indigo”), High Roller Wells Big Lake SWD No. 1 (“Big Lake”) in July 2013, entities affiliated with Oilfield Water Lines, LP (collectively, “OWL”) in August 2013, and Coastal Plains Disposal #1, LLC (“Coastal”) in September 2013. Our natural gas liquids logistics business was expanded through our June 2012 merger with High Sierra, our December 2013 acquisition of Gavilon Energy, and our December 2013 acquisition of four terminals from Keyera Energy, Inc. Our retail propane business was expanded through our May 2012 acquisition of Downeast Energy Corp (“Downeast”).

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.

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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.

At Cushing, Oklahoma, the range of low and high spot prices per barrel of NYMEX West Texas Intermediate Crude Oil and the prices as of period end were as follows:

	Spot Price Per Barrel
	Low		High		At Period End
Three Months Ended:
December 31, 2013	$	92.30	$	104.10	$	98.42
December 31, 2012	84.44		92.39		91.82

Nine Months Ended:
December 31, 2013	$	86.68	$	110.53	$	98.42
December 31, 2012	77.69		106.16		91.82

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

Water Solutions

Our water solutions business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons. Our water processing facilities are strategically located near areas of high crude oil and natural gas production. A significant factor affecting the profitability of our water solutions segment is the extent of exploration and production in the areas near our facilities, which is based upon producers’ expectations about the profitability of drilling new wells. The primary customers of our facility in Wyoming have committed to deliver a specified minimum volume of water to our facility under long-term contracts. The primary customers of our facilities in Colorado have committed to deliver to our facilities all wastewater produced at wells in a designated area. Most of the customers 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 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 products to retailers, refiners, and other participants in the wholesale markets. Our natural gas liquids logistics segment owns 22 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 and gasoline blending have a significant impact on the demand for propane and butane, and sales volumes and prices are typically higher during the colder months of the year. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

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At Conway, Kansas and Mt. Belvieu, Texas, two of our main pricing hubs, the range of low and high spot propane prices per gallon 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

Three Months Ended:
December 31, 2013	$	1.04	$	1.46	$	1.46	$	1.07	$	1.32	$	1.26
December 31, 2012	0.66		0.88		0.83		0.73		1.01		0.90

Nine Months Ended:
December 31, 2013	$	0.77	$	1.46	$	1.46	$	0.81	$	1.32	$	1.26
December 31, 2012	0.50		0.96		0.83		0.71		1.22		0.90

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

	Spot Price Per Gallon
	Low		High		At Period End
Three Months Ended:
December 31, 2013	$	1.30	$	1.54	$	1.38
December 31, 2012	1.44		1.88		1.78

Nine Months Ended:
December 31, 2013	$	1.08	$	1.54	$	1.38
December 31, 2012	1.14		1.93		1.78

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

We acquired Gavilon Energy on December 2, 2013. The operations of Gavilon Energy include a crude oil marketing and logistics business and refined products, ethanol, biodiesel, natural gas liquids, and natural gas marketing businesses. The assets of Gavilon Energy include crude oil terminals in Oklahoma, Louisiana, and Texas, a 50% interest in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oil pipeline in Oklahoma, seven crude oil truck terminals with over twenty pipeline injection stations, and a fleet of leased rail cars and barges.

The operations of the crude oil logistics business of Gavilon Energy are similar to our existing crude oil logistics business described above. Glass Mountain, which became operational in February 2014, transports crude oil from two locations in western Oklahoma to Cushing, Oklahoma.

Gavilon Energy’s refined products marketing business purchases gasoline and diesel fuel primarily from seven suppliers, and sells to over 300 customers. We purchase and sell these products at a nation-wide network of third-party owned terminaling and storage facilities. We typically sell the product at the same time it is purchased in a back-to-back transaction.

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

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

Gavilon Energy’s natural gas marketing business transports, stores, and markets natural gas.

The natural gas liquids marketing business of Gavilon Energy is similar to our existing natural gas liquids logistics business described above.

Summary Discussion of Operating Results for the Three Months Ended December 31, 2013

During the three months ended December 31, 2013, we generated operating income of $41.2 million, compared to operating income of $50.2 million during the three months ended December 31, 2012.

Our crude oil logistics segment generated an operating loss of $6.4 million during the three months ended December 31, 2013, compared to operating income of $11.4 million during the three months ended December 31, 2012. Cost of sales was increased by $3.6 million during the three months ended December 31, 2013 due to unrealized losses on derivatives. Cost of sales was increased by $4.9 million during the three months ended December 31, 2012 due to unrealized losses on derivatives. The impact of these unrealized gains and losses on derivatives impacted the comparability of operating income between the three months ended December 31, 2013 and the three months ended December 31, 2012 by $1.3 million. Acquisitions of business contributed to operating income during the three months ended December 31, 2013, although this benefit was offset by several factors. These factors included a narrowing of price differences between markets, which reduced our opportunities to generate increased margins by transporting product from lower-price to higher-price markets, and increased competition in the South Texas region from newly-constructed pipelines. When price differences between markets are reduced, it is necessary to renegotiate price terms with producers and to not fully utilize our transportation fleet until this process has been completed and margins have improved.

Our water solutions segment generated operating income of $1.0 million during the three months ended December 31, 2013, compared to operating income of $5.5 million during the three months ended December 31, 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 solutions businesses we acquired subsequent to our merger with High Sierra.

Our natural gas liquids logistics segment generated operating income of $40.6 million during the three months ended December 31, 2013, compared to operating income of $25.1 million during the three months ended December 31, 2012. Market demand was greater during the three months ended December 31, 2013 than during the three months ended December 31, 2012, which resulted in higher sales volumes and prices. Due to colder weather conditions, the demand for natural gas liquids increased significantly over the course of the three months ended December 31, 2013. Volumes also improved due to the expansion of our customer base. In addition, during the year ended March 31, 2013, we upgraded two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals. Operating income during the three months ended December 31, 2013 also benefitted from $5.5 million of unrealized gains on derivatives, compared to $5.4 million of unrealized gains on derivatives during the three months ended December 31, 2012.

Our retail propane segment generated operating income of $21.7 million during the three months ended December 31, 2013, compared to operating income of $16.4 million during the three months ended December 31, 2012. The increase in operating income was due primarily to increased market demand due to unusually cold weather conditions.

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We incurred interest expense of $16.7 million during the three months ended December 31, 2013. This was higher than the interest expense of $9.8 million during the three months ended December 31, 2012, due primarily to borrowings to finance acquisitions.

Consolidated Results of Operations

The following table summarizes our historical unaudited consolidated statements of operations for the three months and nine months ended December 31, 2013 and 2012.

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
	(in thousands)
Revenues	$	2,743,445		$	1,338,208		$	5,723,339		$	2,800,154
Cost of sales	2,576,029			1,204,545			5,367,955			2,557,220
Operating and general and administrative expenses	90,753			64,693			228,333			147,865
Depreciation and amortization	35,494			18,747			83,279			41,335
Operating income	41,169			50,223			43,772			53,734
Interest expense	(16,745		)	(9,762		)	(38,427		)	(22,254		)
Loss on early estinguishment of debt	—			—			—			(5,769		)
Other, net	154			261			623			919
Income before income taxes	24,578			40,722			5,968			26,630
Income tax provision	(526		)	(245		)	(356		)	(781		)
Net income	24,052			40,477			5,612			25,849
Net income allocated to general partner	(4,260		)	(942		)	(8,399		)	(1,731		)
Net income attributable to noncontrolling interests	(154		)	(301		)	(288		)	(250		)
Net income (loss) allocated to limited partners	$	19,638		$	39,234		$	(3,075	)	$	23,868

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

Interest Expense

See Note 7 to our condensed consolidated financial statements included 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				Average Debt				Balance
	Outstanding -		Average		Balance				Outstanding -
	Revolving		Interest Rate -		Outstanding -				Unsecured		Interest Rate -
	Facilities		Revolving		Senior Notes		Interest Rate -		Notes		Unsecured
	(in thousands)		Facilities		(in thousands)		Senior Notes		(in thousands)		Notes
Three Months Ended:
December 31, 2013	$	464,370	3.09	%	$	250,000	6.65	%	$	376,630	6.88	%
December 31, 2012	491,847		3.11	%	250,000		6.65	%	—		—
Nine Months Ended:
December 31, 2013	$	502,189	3.47	%	$	250,000	6.65	%	$	126,000	6.88	%
December 31, 2012	377,671		3.39	%	178,182		6.65	%	—		—

Interest expense also includes amortization of debt issuance costs, which represented $1.6 million of expense during the three months ended December 31, 2013 and $0.9 million of expense during the three months ended December 31, 2012. Debt issuance costs represented $4.1 million of expense during the nine months ended December 31, 2013 and $2.3 million of expense during the nine months ended December 31, 2012. Interest expense also includes letter of credit fees, interest on equipment financing notes, and accretion of interest on non-interest bearing debt obligations assumed in business combinations.

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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 nine months ended December 31, 2012.

The increased level of debt outstanding during the three months and nine months ended December 31, 2013 was due primarily to borrowings to finance acquisitions.

Income Tax Provision

See Note 8 to our condensed consolidated financial statements included in this Quarterly Report for additional information on income tax provisions.

Noncontrolling Interests

At December 31, 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 income attributable to parent equity to our EBITDA and Adjusted EBITDA, each of which are non-GAAP financial measures:

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2013			2012			2013		2012
	(in thousands)
EBITDA:
Net income attributable to parent equity	$	23,898		$	40,176		$	5,324	$	25,599
Provision (benefit) for income taxes	526			245			356		781
Interest expense	16,745			9,762			38,427		22,254
Loss on early extinguishment of debt	—			—			—		5,769
Depreciation and amortization expense	36,251			20,494			85,199		44,607
EBITDA	77,420			70,677			129,306		99,010
Unrealized (gain) loss on derivative contracts	(1,954		)	159			1,791		(11,246		)
Loss (gain) on disposal of assets	340			(11		)	2,503		(34		)
Share-based compensation expense	4,078			2,365			14,370		5,322
Adjusted EBITDA	$	79,884		$	73,190		$	147,970	$	93,052

We define EBITDA as net income (loss) attributable to parent equity, plus interest expense, income taxes, 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 accounting principles generally accepted in the United States (“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

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

For purposes of our Adjusted EBITDA calculation, we draw a distinction between unrealized gains and losses on derivatives and realized gains and losses on derivatives. During the period when a derivative contract is open, we record changes in the fair value of the derivative as unrealized gains or losses. When a derivative contract is settled, we reverse the previously-recorded unrealized gain or loss and record a realized gain or loss. The realized gain or loss is equal to the amount received or paid on the contract. We acquired Gavilon Energy in December 2013. We are still in the process of developing procedures to calculate realized and unrealized gains and losses for the Gavilon Energy operations in the same way we calculate them for our other operations. The unrealized gain and loss row in the table above excludes any unrealized gains and losses related to Gavilon Energy, other than $2.6 million of unrealized losses associated with certain specifically identifiable derivative contracts.

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Segment Operating Results for the Three Months Ended December 31, 2013 and 2012

Items Impacting the Comparability of Our Financial Results

Our results of operations for the three months ended December 31, 2013 may not be comparable to our results of operations for the three months ended December 31, 2012, due to a number of business combinations. We have expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of Pecos in November 2012, Third Coast in December 2012, and Crescent in July 2013. We have expanded our water solutions business through several acquisitions of water disposal and transportation businesses in Texas, including Big Lake in July 2013, OWL in August 2013, and Coastal in September 2013.

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 December 31, 2013 are not necessarily indicative of the results to be expected for the full fiscal year.

Volumes

The following table summarizes the volume of product sold and wastewater delivered for the three months ended December 31, 2013 and 2012. Volumes shown in the table below for our natural gas liquids logistics segment include sales to our retail propane segment.

	Three Months Ended
	December 31,
Segment	2013	2012	Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)	13,466	7,461	6,005

Water solutions
Water delivered (barrels)	18,255	9,818	8,437

Natural gas liquids logistics
Propane sold (gallons)	410,286	275,598	134,688
Other products sold (gallons)	207,473	161,258	46,215

Retail propane
Propane sold (gallons)	50,623	42,122	8,501
Distillates sold (gallons)	10,442	8,818	1,624

Volumes sold by our crude oil logistics and water solutions segments were higher during the three months ended December 31, 2013 than during the three months ended December 31, 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 December 31, 2013 than during the three months ended December 31, 2012, due to several factors. Market demand for propane was higher, due in part to unusually cold 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 December 31, 2013 were increased compared to the volumes sold during the three months ended December 31, 2012 due to unusually cold weather conditions.

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Operating Income (Loss) by Segment

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

	Three Months Ended
	December 31,
Segment	2013			2012			Change
	(in thousands)
Crude oil logistics	$	(6,424	)	$	11,407		$	(17,831	)
Water solutions	982			5,499			(4,517		)
Natural gas liquids logistics	40,601			25,090			15,511
Retail propane	21,696			16,437			5,259
Corporate and other	(15,686		)	(8,210		)	(7,476		)
Operating income	$	41,169		$	50,223		$	(9,054	)

The operating loss within “corporate and other” during the three months ended December 31, 2013 includes $4.1 million of expense related to equity-based compensation, $5.1 million of expense related to acquisitions, and $4.6 million of other corporate expenses.

The operating loss within “corporate and other” during the three months ended December 31, 2012 includes $2.4 million of expense related to equity-based compensation, $0.8 million of expense related to acquisitions, and $3.1 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 December 31, 2013 than during the three months ended December 31, 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 December 31, 2013 than at December 31, 2012.

The increase in acquisition-related expenses is due primarily to $5.0 million of expenses related to the acquisition of Gavilon Energy.

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, and the operations of our fuels marketing and natural gas marketing businesses, which we acquired in our acquisition of Gavilon Energy, are also included within “corporate and other.” On a combined basis, these operations generated an operating loss of $1.9 million during the three months ended December 31, 2013.

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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 December 31, 2013 and 2012:

	Three Months Ended
	December 31,
	2013			2012		Change
	(in thousands)
Revenues:
Crude oil sales	$	1,319,290		$	683,054	$	636,236
Other revenues	6,198			1,174		5,024
Total revenues(1)	1,325,488			684,228		641,260
Expenses:
Cost of sales	1,310,339			661,219		649,120
Operating expenses	14,336			8,631		5,705
General and administrative expenses	1,410			1,067		343
Depreciation and amortization expense	5,827			1,904		3,923
Total expenses	1,331,912			672,821		659,091

Segment operating income (loss)	$	(6,424	)	$	11,407	$	(17,831	)

(1) Revenues include $9.4 million of intersegment sales during the three months ended December 31, 2013 and $6.2 million of intersegment sales during the three months ended December 31, 2012 that are eliminated in our consolidated statements of operations.

Revenues. Our crude oil logistics segment generated $1.3 billion of revenue from crude oil sales during the three months ended December 31, 2013, selling 13.5 million barrels at an average price of $97.97 per barrel. During the three months ended December 31, 2012, our crude oil logistics segment generated $683.1 million of revenue from crude oil sales, selling 7.5 million barrels at an average price of $91.55 per barrel. The increase in volume during the three months ended December 31, 2013 compared to the three months ended December 31, 2012 was due primarily to acquisitions of crude oil logistics businesses, including Gavilon Energy, Pecos, and Third Coast, among others.

Other revenues of our crude oil logistics segment were $6.2 million during the three months ended December 31, 2013, compared to $1.2 million of other revenues during the three months ended December 31, 2012. This increase was due primarily to acquisitions of crude oil logistics businesses, including Pecos and Third Coast.

Cost of Sales. Our cost of crude oil sold was $1.3 billion during the three months ended December 31, 2013, selling 13.5 million barrels at an average cost of $97.31 per barrel. Our cost of sales during the three months ended December 31, 2013 was increased by $3.6 million of unrealized losses on derivatives. During the three months ended December 31, 2012, our cost of crude oil sold was $661.2 million, selling 7.5 million barrels at an average cost of $88.62 per barrel. Our cost of sales during the three months ended December 31, 2012 included $4.9 million of unrealized losses on derivatives.

Operating Expenses. Our crude oil logistics segment generated $14.3 million of operating expenses during the three months ended December 31, 2013, compared to $8.6 million of operating expenses during the three months ended December 31, 2012. This increase was due primarily to the expansion of operations resulting from acquisitions, including Gavilon Energy, Pecos, and Third Coast.

General and Administrative Expenses. Our crude oil logistics segment generated $1.4 million of general and administrative expenses during the three months ended December 31, 2013, compared to $1.1 million of general and administrative expenses during the three months ended December 31, 2012. This increase was due primarily to the expansion of operations resulting from acquisitions.

Depreciation and Amortization Expense. Our crude oil logistics segment generated $5.8 million of depreciation and amortization expense during the three months ended December 31, 2013, compared to $1.9 million of depreciation and amortization

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expense during the three months ended December 31, 2012. This increase was due primarily to the expansion of operations resulting from acquisitions.

Operating Income. Our crude oil logistics segment generated an operating loss of $6.4 million during the three months ended December 31, 2013, compared to $11.4 million of operating income during the three months ended December 31, 2012. Cost of sales was increased by $3.6 million during the three months ended December 31, 2013 due to unrealized losses on derivatives. Cost of sales was increased by $4.9 million during the three months ended December 31, 2012 due to unrealized losses on derivatives. The impact of these unrealized gains and losses on derivatives impacted the comparability of operating income between the three months ended December 31, 2013 and the three months ended December 31, 2012 by $1.3 million. Acquisitions of business contributed to operating income during the three months ended December 31, 2013, although this benefit was offset by several factors. These factors included a narrowing of price differences between markets, which reduced our opportunities to generate increased margins by transporting product from lower-price to higher-price markets, and increased competition in the South Texas region from newly-constructed pipelines. When price differences between markets are reduced, it is necessary to renegotiate price terms with producers and to not fully utilize our transportation fleet until this process has been completed and margins have improved.

Water Solutions

The following table summarizes the operating results of our water solutions segment for the three months ended December 31, 2013 and 2012:

	Three Months Ended
	December 31,				Change
	2013		2012		Acquisitions (1)			Other
	(in thousands)
Revenues:
Water treatment and disposal	$	36,282	$	20,563	$	14,993		$	726
Water transportation	5,490		2,243		5,013			(1,766		)
Total revenues	41,772		22,806		20,006			(1,040		)
Expenses:
Cost of sales	2,571		1,499		3,520			(2,448		)
Operating expenses	18,866		8,035		10,735			96
General and administrative expenses	1,095		538		540			17
Depreciation and amortization expense	18,258		7,235		11,622			(599		)
Total expenses	40,790		17,307		26,417			(2,934		)

Segment operating income	$	982	$	5,499	$	(6,411	)	$	1,894

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

Revenues. Our water solutions segment generated $36.3 million of treatment and disposal revenue during the three months ended December 31, 2013, taking delivery of 18.3 million barrels of wastewater at an average revenue of $1.99 per barrel. During the three months ended December 31, 2012, our water solutions segment generated $20.6 million of treatment and disposal revenue, taking delivery of 9.8 million barrels of wastewater at an average revenue of $2.09 per barrel. The increase in revenues was due primarily to acquisitions, including OWL, Big Lake, and Coastal. The decrease in revenue per barrel was due primarily to the fact that the expansion of our water solutions business subsequent to our merger with High Sierra has been primarily in Texas, where the market rates for water disposal services are typically lower than in Wyoming and Colorado.

In our June 2012 merger with High Sierra, we acquired a water transportation business in Oklahoma. In our August 2013 acquisition of OWL, we acquired a water transportation business in Texas. Our water solutions segment generated $5.5 million of transportation revenues during the three months ended December 31, 2013, compared to $2.2 million of transportation revenues during the three months ended December 31, 2012. This increase was due primarily to the acquisition of OWL. This increase was partially offset by a decrease in water transportation revenues generated by the water solutions business acquired in the merger with High Sierra, which resulted primarily from a slowdown in production activities by a customer. During the three months ended December 31, 2013, we wound down our water transportation operations in Oklahoma. We transferred certain of the assets to our business in Texas and sold the remaining assets.

Cost of Sales. The cost of sales for our water solutions segment was $2.6 million during the three months ended December 31, 2013. Our cost of sales during the three months ended December 31, 2013 was reduced by $0.5 million of net gains on derivatives,

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which included $0.7 million of unrealized gains that were partially offset by $0.2 million of realized losses. Because a portion of our processing revenue is generated from the sale of recovered hydrocarbons, we enter into derivatives to protect against the risk of a decline in the market price of a portion of the hydrocarbons we expect to recover. During the three months ended December 31, 2012, the cost of sales for our water solutions segment was $1.5 million. Our cost of sales during the three months ended December 31, 2012 was reduced by $0.3 million of unrealized gains on derivatives, partially offset by $0.1 million of realized losses on derivatives. The increase in our cost of sales was due primarily to the expansion of our operations through acquisitions of businesses.

Operating Expenses. Our water solutions segment generated $18.9 million of operating expenses during the three months ended December 31, 2013, compared to $8.0 million of operating expenses during the three months ended December 31, 2012. This increase was due primarily to acquisitions of businesses.

General and Administrative Expenses. Our water solutions segment generated $1.1 million of general and administrative expenses during the three months ended December 31, 2013, compared to $0.5 million of general and administrative expenses during the three months ended December 31, 2012. This increase was due primarily to acquisitions of businesses.

Depreciation and Amortization Expense. Our water solutions segment generated $18.3 million of depreciation and amortization expense during the three months ended December 31, 2013, compared to $7.2 million of depreciation and amortization expense during the three months ended December 31, 2012. This increase was due primarily to acquisitions of businesses.

Operating Income. Our water solutions segment generated $1.0 million of operating income during the three months ended December 31, 2013, compared to $5.5 million of operating income during the three months ended December 31, 2012. Exclusive of acquisitions during the nine months ended December 31, 2013, our operating income increased by $1.9 million. The businesses acquired during the nine months ended December 31, 2013 generated an operating loss of $6.4 million, which included $11.6 million of depreciation and amortization expense, which consisted primarily of amortization on acquired customer relationship intangible assets.

Natural Gas Liquids Logistics

The following table summarizes the operating results of our natural gas liquids logistics segment for the three months ended December 31, 2013 and 2012:

	Three Months Ended
	December 31,
	2013		2012		Change
	(in thousands)
Revenues:
Propane sales	$	518,541	$	255,157	$	263,384
Other product sales	336,654		286,598		50,056
Other revenues	7,695		8,822		(1,127		)
Total revenues (1)	862,890		550,577		312,313

Expenses:
Cost of sales - propane	487,190		242,642		244,548
Cost of sales - other products	314,102		266,665		47,437
Cost of sales - other	6,577		3,760		2,817
Operating expenses	9,874		8,758		1,116
General and administrative expenses	1,787		1,397		390
Depreciation and amortization expense	2,759		2,265		494
Total expenses	822,289		525,487		296,802

Segment operating income	$	40,601	$	25,090	$	15,511

(1) Revenues include $62.0 million of sales to our retail propane and crude oil logistics segments during the three months ended December 31, 2013 and $42.4 million of intersegment sales during the three months ended December 31, 2012 that are eliminated in our consolidated statements of operations.

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Revenues. Our natural gas liquids logistics segment generated $518.5 million of wholesale propane sales revenue during the three months ended December 31, 2013, selling 410.3 million gallons at an average price of $1.26 per gallon. During the three months ended December 31, 2012, our natural gas liquids logistics segment generated $255.2 million of wholesale propane sales revenue, selling 275.6 million gallons at an average price of $0.93 per gallon. The increase in volumes during the three months ended December 31, 2013 as compared to the three months ended December 31, 2012 was due to several factors. Market demand was higher, due in part to colder weather conditions. Volumes also increased due to the expansion of our customer base. In addition, during the year ended March 31, 2013, we upgraded two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

Our natural gas liquids logistics segment generated $336.7 million of other wholesale products sales revenue during the three months ended December 31, 2013, selling 207.5 million gallons at an average price of $1.62 per gallon. During the three months ended December 31, 2012, our natural gas liquids logistics segment generated $286.6 million of other wholesale products sales revenue, selling 161.3 million gallons at an average price of $1.78 per gallon. The increase in volumes during the three months ended December 31, 2013 as compared to the three months ended December 31, 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 customer base and to an increased focus on the opportunity to more fully utilize our terminals to market butane.

Cost of Sales. Our cost of wholesale propane sales was $487.2 million during the three months ended December 31, 2013, selling 410.3 million gallons at an average cost of $1.19 per gallon. Our cost of wholesale propane sales during the three months ended December 31, 2013 was increased by $0.1 million of unrealized losses on derivatives. During the three months ended December 31, 2012, our cost of wholesale propane sales was $242.6 million, selling 275.6 million gallons at an average cost of $0.88 per gallon. Our cost of wholesale propane sales during the three months ended December 31, 2012 was increased by $5.2 million of unrealized losses on derivatives.

Our cost of sales of other products was $314.1 million during the three months ended December 31, 2013, selling 207.5 million gallons at an average cost of $1.51 per gallon. Our cost of sales of other products during the three months ended December 31, 2013 was reduced by $5.6 million of unrealized gains on derivatives. During the three months ended December 31, 2012, our cost of sales of other products was $266.7 million, selling 161.3 million gallons at an average cost of $1.65 per gallon. Our cost of sales of other products during the three months ended December 31, 2012 was reduced by $10.6 million of unrealized gains on derivatives.

Operating Expenses. Our natural gas liquids logistics segment generated $9.9 million of operating expenses during the three months ended December 31, 2013, compared to $8.8 million of operating expenses during the three months ended December 31, 2012. This increase was due primarily to expanded operations.

General and Administrative Expenses. Our natural gas liquids logistics segment generated $1.8 million of general and administrative expenses during the three months ended December 31, 2013, compared to $1.4 million of general and administrative expenses during the three months ended December 31, 2012.

Depreciation and Amortization Expense. Our natural gas liquids logistics segment generated $2.8 million of depreciation and amortization expense during the three months ended December 31, 2013, compared to $2.3 million of depreciation and amortization expense during the three months ended December 31, 2012. This increase was due primarily to depreciation expense on capital expansion and improvement processes that were completed during the fiscal year ended March 31, 2013 and the nine months ended December 31, 2013.

Operating Income. Our natural gas liquids logistics segment generated $40.6 million of operating income during the three months ended December 31, 2013, compared to $25.1 million of operating income during the three months ended December 31, 2012. The increase in operating income was due primarily to the expansion of our operations and to colder weather conditions. The demand for natural gas liquids increased considerably over the course of the three months ended December 31, 2013, which had a favorable impact on our sales volumes. The demand has also resulted in increases to market prices for natural gas liquids, which had a favorable impact on product margins, as we purchased inventory when prices, and therefore our average cost of inventory, were lower than they are today.

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Retail Propane

The following table summarizes the operating results of our retail propane segment for the three months ended December 31, 2013 and 2012:

	Three Months Ended
	December 31,
	2013		2012		Change
	(in thousands)
Revenues:
Propane sales	$	112,570	$	84,258	$	28,312
Distillate sales	37,648		33,062		4,586
Other revenues	11,377		10,585		792
Total revenues	161,595		127,905		33,690
Expenses:
Cost of sales - propane	68,763		44,961		23,802
Cost of sales - distillates	32,406		28,986		3,420
Cost of sales - other	4,283		3,502		781
Operating expenses	23,773		24,125		(352		)
General and administrative expenses	3,330		2,907		423
Depreciation and amortization expense	7,344		6,987		357
Total expenses	139,899		111,468		28,431

Segment operating income	$	21,696	$	16,437	$	5,259

Revenues. Our retail propane segment generated $112.6 million of propane sales revenue during the three months ended December 31, 2013, selling 50.6 million gallons at an average price of $2.22 per gallon. During the three months ended December 31, 2012, our retail propane segment generated $84.3 million of propane sales revenue, selling 42.1 million gallons at an average price of $2.00 per gallon. The increase in volumes and average sales prices during the three months ended December 31, 2013 compared to the three months ended December 31, 2012 was due primarily to market demand being higher as a result of colder weather conditions. Revenues also benefitted from the continued integration of previously-acquired businesses.

Our retail propane segment generated $37.6 million of distillate sales revenue during the three months ended December 31, 2013, selling 10.4 million gallons at an average price of $3.61 per gallon. During the three months ended December 31, 2012, our retail propane segment generated $33.1 million of other distillate sales revenue, selling 8.8 million gallons at an average price of $3.75 per gallon.

Cost of Sales. Our cost of retail propane sales was $68.8 million during the three months ended December 31, 2013, selling 50.6 million gallons at an average cost of $1.36 per gallon. During the three months ended December 31, 2012, our cost of retail propane sales was $45.0 million, selling 42.1 million gallons at an average cost of $1.07 per gallon. The increase in average product margin per gallon was due primarily to the fact that propane prices increased over the course of the three months ended December 31, 2013, and the weighted-average inventory cost included inventory that had been purchased when prices were lower.

Our cost of distillate sales was $32.4 million during the three months ended December 31, 2013, selling 10.4 million gallons at an average cost of $3.10 per gallon. During the three months ended December 31, 2012, our cost of distillate sales was $29.0 million, selling 8.8 million gallons at an average cost of $3.29 per gallon. Our cost of distillate sales during the three months ended December 31, 2012 was increased by $0.9 million of unrealized losses on derivatives. Unrealized losses on derivatives were not significant during the three months ended December 31, 2013.

Operating Expenses. Our retail propane segment generated $23.8 million of operating expenses during the three months ended December 31, 2013, compared to $24.1 million of operating expenses during the three months ended December 31, 2012. This decrease was due primarily to efficiencies from business combinations.

General and Administrative Expenses. Our retail propane segment generated $3.3 million of general and administrative expenses during the three months ended December 31, 2013, compared to $2.9 million of general and administrative expenses during the three months ended December 31, 2012.

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Depreciation and Amortization Expense. Our retail propane segment generated $7.3 million of depreciation and amortization expense during the three months ended December 31, 2013, compared to $7.0 million of depreciation and amortization expense during the three months ended December 31, 2012.

Operating Income. Our retail propane segment generated $21.7 million of operating income during the three months ended December 31, 2013, compared to $16.4 million of operating income during the three months ended December 31, 2012. The increase in operating income was due primarily to increased market demand due to colder weather conditions.

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Segment Operating Results for the Nine Months Ended December 31, 2013 and 2012

Items Impacting the Comparability of Our Financial Results

Our results of operations for the nine months ended December 31, 2013 may not be comparable to our results of operations for the nine months ended December 31, 2012, due to a number of business combinations. Our crude oil logistics and water solutions businesses began with our June 19, 2012 merger with High Sierra Energy, LP and High Sierra Energy GP, LLC (collectively, “High Sierra”). This merger also significantly expanded our natural gas liquids logistics operations. We subsequently expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of Pecos in November 2012, Third Coast in December 2012, and Crescent in July 2013. We also expanded our water solutions business through several acquisitions of water disposal and transportation businesses in Texas, including Indigo in October 2012, Big Lake in July 2013, OWL in August 2013, and Coastal in September 2013.

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 nine months ended December 31, 2013 are not necessarily indicative of the results to be expected for the full fiscal year.

Volumes

The following table summarizes the volume of product sold and wastewater delivered for the nine months ended December 31, 2013 and 2012. Volumes shown in the table below for our natural gas liquids logistics segment include sales to our retail propane segment.

	Nine Months Ended
	December 31,
Segment	2013	2012	Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)	32,001	15,922	16,079

Water solutions
Water delivered (barrels)	44,753	16,593	28,160

Natural gas liquids logistics
Propane sold (gallons)	721,120	532,353	188,767
Other products sold (gallons)	581,195	370,365	210,830

Retail propane
Propane sold (gallons)	94,615	81,449	13,166
Distillates sold (gallons)	18,618	15,091	3,527

Volumes sold by our crude oil logistics and water solutions segments were higher during the nine months ended December 31, 2013 than during the nine months ended December 31, 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 nine months ended December 31, 2013 than during the nine months ended December 31, 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 customer base. In addition, during the year ended March 31, 2013, we upgraded two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

Volumes sold by our retail propane segment during the nine months ended December 31, 2013 were increased compared to the volumes sold during the nine months ended December 31, 2012 due to colder weather conditions.

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Operating Income (Loss) by Segment

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

	Nine Months Ended
	December 31,
Segment	2013			2012			Change
	(in thousands)
Crude oil logistics	$	6,069		$	17,226		$	(11,157	)
Water solutions	6,938			10,046			(3,108		)
Natural gas liquids logistics	53,091			36,492			16,599
Retail propane	15,672			9,797			5,875
Corporate and other	(37,998		)	(19,827		)	(18,171		)
Operating income	$	43,772		$	53,734		$	(9,962	)

The operating loss within “corporate and other” during the nine months ended December 31, 2013 includes $14.4 million of expense related to equity-based compensation, $6.5 million of expense related to acquisitions, and $14.9 million of other corporate expenses.

The operating loss within “corporate and other” during the nine months ended December 31, 2012 includes $5.3 million of expense related to equity-based compensation, $5.2 million of expense related to acquisitions, and $8.4 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 December 31, 2013 than at December 31, 2012.

The operations of our compressor leasing business, which was acquired in our June 2012 merger with High Sierra, and the operations of our fuels marketing and natural gas marketing businesses, which we acquired in our acquisition of Gavilon Energy, are also included within “corporate and other.” On a combined basis, these operations generated an operating loss of $2.2 million during the nine months ended December 31, 2013.

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Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the nine months ended December 31, 2013 and 2012:

	Nine Months Ended
	December 31,
	2013		2012		Change
	(in thousands)
Revenues:
Crude oil sales	$	3,260,885	$	1,468,731	$	1,792,154
Other revenues	25,927		3,708		22,219
Total revenues(1)	3,286,812		1,472,439		1,814,373
Expenses:
Cost of sales	3,228,215		1,435,462		1,792,753
Operating expenses	35,512		14,057		21,455
General and administrative expenses	3,175		1,850		1,325
Depreciation and amortization expense	13,841		3,844		9,997
Total expenses	3,280,743		1,455,213		1,825,530

Segment operating income	$	6,069	$	17,226	$	(11,157	)

(1) Revenues include $26.0 million of intersegment sales during the nine months ended December 31, 2013 and $9.9 million of intersegment sales during the nine months ended December 31, 2012 that are eliminated in our consolidated statements of operations.

Revenues. Our crude oil logistics segment generated $3.3 billion of revenue from crude oil sales during the nine months ended December 31, 2013, selling 32.0 million barrels at an average price of $101.90 per barrel. During the nine months ended December 31, 2012, our crude oil logistics segment generated $1.5 billion of revenue from crude oil sales, selling 15.9 million barrels at an average price of $92.25 per barrel. The increase in volume during the nine months ended December 31, 2013 compared to the nine months ended December 31, 2012 was 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 acquired this business in our June 19, 2012 merger with High Sierra. The increase in volume was also due to acquisitions of crude oil logistics businesses, including Gavilon Energy, Pecos, and Third Coast, among others.

Other revenues of our crude oil logistics segment were $25.9 million during the nine months ended December 31, 2013, compared to $3.7 million of other revenues during the nine months ended December 31, 2012. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to acquisitions of crude oil logistics businesses, including Pecos and Third Coast.

Cost of Sales. Our cost of crude oil sold was $3.2 billion during the nine months ended December 31, 2013, selling 32.0 million barrels at an average cost of $100.88 per barrel. Our cost of sales during the nine months ended December 31, 2013 was increased by $2.1 million of unrealized losses on derivatives. During the nine months ended December 31, 2012, our cost of crude oil was $1.4 billion, selling 15.9 million barrels at an average cost of $90.16 per barrel. Our cost of sales during the nine months ended December 31, 2012 was increased by $2.9 million of unrealized losses on derivatives.

Operating Expenses. Our crude oil logistics segment generated $35.5 million of operating expenses during the nine months ended December 31, 2013, compared to $14.1 million of operating expenses during the nine months ended December 31, 2012. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to the expansion of operations resulting from acquisitions, including Gavilon Energy, Pecos, and Third Coast.

General and Administrative Expenses. Our crude oil logistics segment generated $3.2 million of general and administrative expenses during the nine months ended December 31, 2013, compared to $1.9 million of general and administrative expenses during the nine months ended December 31, 2012. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to the expansion of operations resulting from acquisitions.

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Depreciation and Amortization Expense. Our crude oil logistics segment generated $13.8 million of depreciation and amortization expense during the nine months ended December 31, 2013, compared to $3.8 million of depreciation and amortization expense during the nine months ended December 31, 2012. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to the expansion of operations resulting from acquisitions.

Operating Income. Our crude oil logistics segment generated $6.1 million of operating income during the nine months ended December 31, 2013, compared to $17.2 million of operating income during the nine months ended December 31, 2012. Acquisitions of business contributed to operating income during the nine months ended December 31, 2013, although this benefit was offset by several factors. These factors included a narrowing of price differences between markets, which reduced our opportunities to generate increased margins by transporting product from lower-price to higher-price markets, and increased competition in the South Texas region from newly-constructed pipelines. When price differences between markets are reduced, it is necessary to renegotiate price terms with producers and to not fully utilize our transportation fleet until this process has been completed and margins have improved.

Water Solutions

The following table summarizes the operating results of our water solutions segment for the nine months ended December 31, 2013 and 2012:

	Nine Months Ended
	December 31,				Change
	2013		2012		Acquisitions (1)			Other
	(in thousands)
Revenues:
Water treatment and disposal	$	83,793	$	34,799	$	36,475		$	12,519
Water transportation	12,682		5,758		8,886			(1,962		)
Total revenues	96,475		40,557		45,361			10,557
Expenses:
Cost of sales	6,936		4,169		5,893			(3,126		)
Operating expenses	42,876		14,993		23,344			4,539
General and administrative expenses	2,673		1,064		795			814
Depreciation and amortization expense	37,052		10,285		17,193			9,574
Total expenses	89,537		30,511		47,225			11,801

Segment operating income	$	6,938	$	10,046	$	(1,864	)	$	(1,244	)

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

Revenues. Our water solutions segment generated $83.8 million of treatment and disposal revenue during the nine months ended December 31, 2013, taking delivery of 44.8 million barrels of wastewater at an average revenue of $1.87 per barrel. During the nine months ended December 31, 2012, our water solutions segment generated $34.8 million of treatment and disposal revenue, taking delivery of 16.6 million barrels of wastewater at an average revenue of $2.10 per barrel. The increase in revenues was due primarily to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra and was due also to acquisitions during the fiscal year ended March 31, 2013, including Indigo, OWL, Big Lake and Coastal. The decrease in revenue per barrel was due primarily to the fact that the expansion of our water solutions business subsequent to our merger with High Sierra has been primarily in Texas, where the market rates for water disposal services are typically lower than in Wyoming or Colorado.

In our June 2012 merger with High Sierra, we acquired a water transportation business in Oklahoma. In our August 2013 acquisition of OWL, we acquired a water transportation business in Texas. Our water solutions segment generated $12.7 million of transportation revenues during the nine months ended December 31, 2013, compared to $5.8 million of transportation revenues during the nine months ended December 31, 2012. This increase was due primarily to the acquisition of OWL. This increase was partially offset by a decrease in water transportation revenues generated by the water solutions business acquired in the merger with High Sierra, which resulted primarily from a slowdown in production

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activities by a customer. During the three months ended December 31, 2013, we wound down our water transportation operations in Oklahoma. We transferred certain of the assets to our business in Texas and sold the remaining assets.

Cost of Sales. The cost of sales for our water solutions segment was $6.9 million during the nine months ended December 31, 2013. Our cost of sales during the nine months ended December 31, 2013 included $1.3 million of realized losses on derivatives, which were partially offset by $1.0 million of unrealized gains 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 nine months ended December 31, 2012, the cost of sales for our water solutions segment was $4.2 million. Our cost of sales during the nine months ended December 31, 2012 was increased by $1.0 million of unrealized losses and $0.5 million of realized losses on derivatives. The increase in our cost of sales was due primarily to the expansion of our operations through acquisitions of water solutions businesses.

Operating Expenses. Our water solutions segment generated $42.9 million of operating expenses during the nine months ended December 31, 2013, compared to $15.0 million of operating expenses during the nine months ended December 31, 2012. This increase was due primarily to the fact that we did not own a water services business until our June 19, 2012 merger with High Sierra, and was also due primarily to subsequent acquisitions of businesses. We incurred losses on disposal of property, plant and equipment of $2.0 million during the nine months ended December 31, 2013 as a result of property damage resulting from lightning strikes at two of our facilities.

General and Administrative Expenses. Our water solutions segment generated $2.7 million of general and administrative expenses during the nine months ended December 31, 2013, compared to $1.1 million of general and administrative expenses during the nine months ended December 31, 2012. This increase was due in part to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra, and was also due primarily to subsequent acquisitions of businesses.

Depreciation and Amortization Expense. Our water solutions segment generated $37.1 million of depreciation and amortization expense during the nine months ended December 31, 2013, compared to $10.3 million of depreciation and amortization expense during the nine months ended December 31, 2012. This increase was due in part to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra, and was also due primarily to subsequent acquisitions of businesses.

Operating Income. Our water solutions segment generated $6.9 million of operating income during the nine months ended December 31, 2013, compared to operating income of $10.0 million during the nine months ended December 31, 2012. Exclusive of acquisitions during the nine months ended December 31, 2013, our operating income decreased by $1.2 million. Increases in revenues were offset by increases in operating expenses, including a $9.6 million increase in depreciation and amortization expense. The businesses acquired during the nine months ended December 31, 2013 generated an operating loss of $1.9 million, which included $17.2 million of depreciation and amortization expense, which consisted primarily of amortization expense on acquired customer relationship intangible assets.

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Natural Gas Liquids Logistics

The following table summarizes the operating results of our natural gas liquids logistics segment for the nine months ended December 31, 2013 and 2012:

	Nine Months Ended
	December 31,
	2013		2012		Change
	(in thousands)
Revenues:
Propane sales	$	833,815	$	477,981	$	355,834
Other product sales	895,113		626,360		268,753
Other revenues	25,809		17,143		8,666
Total revenues (1)	1,754,737		1,121,484		633,253

Expenses:
Cost of sales - propane	789,298		450,803		338,495
Cost of sales - other products	855,179		594,616		260,563
Cost of sales - other	19,051		8,898		10,153
Operating expenses	25,406		19,264		6,142
General and administrative expenses	4,577		3,696		881
Depreciation and amortization expense	8,135		7,715		420
Total expenses	1,701,646		1,084,992		616,654

Segment operating income	$	53,091	$	36,492	$	16,599

(1) Revenues include $108.0 million of intersegment sales during the nine months ended December 31, 2013 and $71.4 million of intersegment sales during the nine months ended December 31, 2012 that are eliminated in our consolidated statements of operations.

Revenues. Our natural gas liquids logistics segment generated $833.8 million of wholesale propane sales revenue during the nine months ended December 31, 2013, selling 721.1 million gallons at an average price of $1.16 per gallon. During the nine months ended December 31, 2012, our natural gas liquids logistics segment generated $478.0 million of wholesale propane sales revenue, selling 532.4 million gallons at an average price of $0.90 per gallon. Approximately 43.5 million gallons of the increase in volumes was due to the fact that we only owned the natural gas liquids business of High Sierra for a part of the nine months ended December 31, 2012. The remaining increase in volume was due to several factors. Market demand was higher, due in part to colder weather conditions. Volumes also increased due to the expansion of our customer base. In addition, during the year ended March 31, 2013, we upgraded two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

Our natural gas liquids logistics segment generated $895.1 million of other wholesale products sales revenue during the nine months ended December 31, 2013, selling 581.2 million gallons at an average price of $1.54 per gallon. During the nine months ended December 31, 2012, our natural gas liquids logistics segment generated $626.4 million of other wholesale products sales revenue, selling 370.4 million gallons at an average price of $1.69 per gallon. Approximately 106.1 million gallons of the increase in volumes was due to the fact that we only owned the natural gas liquids business of High Sierra for a part of the nine months ended December 31, 2012. The remaining increase in volume was 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 customer base and to an increased focus on the opportunity to more fully utilize our terminals to market butane.

Cost of Sales. Our cost of wholesale propane sales was $789.3 million during the nine months ended December 31, 2013, selling 721.1 million gallons at an average cost of $1.09 per gallon. Our cost of wholesale propane sales during the nine months ended December 31, 2013 was increased by $5.3 million of unrealized losses on derivatives. During the nine months ended December 31, 2012, our cost of wholesale propane sales was $450.8 million, selling 532.4 million gallons at an average cost of $0.85 per gallon. Our cost of wholesale propane sales during the nine months ended December 31, 2012 was reduced by $5.9 million of unrealized gains on derivatives.

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Declining wholesale propane prices during the first quarter of the prior fiscal year had an adverse effect on cost of sales during the nine months ended December 31, 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.

Our cost of sales of other products was $855.2 million during the nine months ended December 31, 2013, selling 581.2 million gallons at an average cost of $1.47 per gallon. Our cost of sales of other products during the nine months ended December 31, 2013 was reduced by $5.3 million of unrealized gains on derivatives. During the nine months ended December 31, 2012, our cost of sales of other products was $594.6 million, selling 370.4 million gallons at an average cost of $1.61 per gallon. Our cost of sales of other products during the nine months ended December 31, 2012 was reduced by $9.3 million of unrealized gains on derivatives.

Operating Expenses. Our natural gas liquids logistics segment generated $25.4 million of operating expenses during the nine months ended December 31, 2013, compared to $19.3 million of operating expenses during the nine months ended December 31, 2012. This increase was due primarily to expanded operations.

General and Administrative Expenses. Our natural gas liquids logistics segment generated $4.6 million of general and administrative expenses during the nine months ended December 31, 2013, compared to $3.7 million of general and administrative expenses during the nine months ended December 31, 2012. This increase was due primarily to expanded operations.

Depreciation and Amortization Expense. Our natural gas liquids logistics segment generated $8.1 million of depreciation and amortization expense during the nine months ended December 31, 2013, compared to $7.7 million of depreciation and amortization expense during the nine months ended December 31, 2012. This increase was due primarily to depreciation expense on capital expansion and improvement processes that were completed during the fiscal year ended March 31, 2013 and the nine months ended December 31, 2013.

Operating Income. Our natural gas liquids logistics segment generated $53.1 million of operating income during the nine months ended December 31, 2013, compared to $36.5 million of operating income during the nine months ended December 31, 2012. The increase in operating income was due primarily to the expansion of our operations and to colder weather conditions. As a result of the cold weather conditions, the demand for natural gas liquids increased considerably over the course of the three months ended December 31, 2013, which had a favorable impact on our sales volumes. The demand has also resulted in increases to market prices for natural gas liquids, which had a favorable impact on product margins, as we purchased inventory when prices, and therefore our average cost of inventory, were lower than they are today. These increases were partially offset by increased operating expenses as a result of expanding our operations. Operating income during the nine months ended December 31, 2012 benefitted from $15.2 million of unrealized gains on derivatives. During the nine months ended December 31, 2013, net unrealized gains on derivatives were not significant.

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Retail Propane

The following table summarizes the operating results of our retail propane segment for the nine months ended December 31, 2013 and 2012:

	Nine Months Ended
	December 31,
	2013		2012		Change
	(in thousands)
Revenues:
Propane sales	$	199,912	$	162,049	$	37,863
Distillate sales	66,079		55,685		10,394
Other revenues	27,275		26,382		893
Total revenues	293,266		244,116		49,150
Expenses:
Cost of sales - propane	115,790		87,450		28,340
Cost of sales - distillates	56,915		47,883		9,032
Cost of sales - other	9,383		9,223		160
Operating expenses	65,612		63,193		2,419
General and administrative expenses	8,439		7,655		784
Depreciation and amortization expense	21,455		18,915		2,540
Total expenses	277,594		234,319		43,275

Segment operating income	$	15,672	$	9,797	$	5,875

Revenues. Our retail propane segment generated $199.9 million of propane sales revenue during the nine months ended December 31, 2013, selling 94.6 million gallons at an average price of $2.11 per gallon. During the nine months ended December 31, 2012, our retail propane segment generated $162.0 million of propane sales revenue, selling 81.4 million gallons at an average price of $1.99 per gallon. The increase in volumes and average sales prices during the nine months ended December 31, 2013 compared to the nine months ended December 31, 2012 was due primarily to market demand being higher as a result of colder weather conditions. Revenues also benefitted from the continued integration of previously-acquired businesses.

Our retail propane segment generated $66.1 million of distillate sales revenue during the nine months ended December 31, 2013, selling 18.6 million gallons at an average price of $3.55 per gallon. During the nine months ended December 31, 2012, our retail propane segment generated $55.7 million of other distillate sales revenue, selling 15.1 million gallons at an average price of $3.69 per gallon. The increase in volumes 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 eight of the months in the nine-month period ended December 31, 2012.

Cost of Sales. Our cost of retail propane sales was $115.8 million during the nine months ended December 31, 2013, selling 94.6 million gallons at an average cost of $1.22 per gallon. During the nine months ended December 31, 2012, our cost of retail propane sales was $87.5 million, selling 81.4 million gallons at an average cost of $1.07 per gallon.

Our cost of distillate sales was $56.9 million during the nine months ended December 31, 2013, selling 18.6 million gallons at an average cost of $3.06 per gallon. During the nine months ended December 31, 2012, our cost of distillate sales was $47.9 million, selling 15.1 million gallons at an average cost of $3.17 per gallon.

Operating Expenses. Our retail propane segment generated $65.6 million of operating expenses during the nine months ended December 31, 2013, compared to $63.2 million of operating expenses during the nine months ended December 31, 2012. This increase was due in part to the inclusion of Downeast in our results of operations for the full nine months ended December 31, 2013, as compared to only eight of the months in the nine-month period ended December 31, 2012.

General and Administrative Expenses. Our retail propane segment generated $8.4 million of general and administrative expenses during the nine months ended December 31, 2013, compared to $7.7 million of general and administrative expenses during the nine months ended December 31, 2012. This increase was due in part to the inclusion of Downeast in our results of operations for the full nine months ended December 31, 2013, as compared to only eight of the months in the nine-month period ended December 31, 2012.

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Depreciation and Amortization Expense. Our retail propane segment generated $21.5 million of depreciation and amortization expense during the nine months ended December 31, 2013, compared to $18.9 million of depreciation and amortization expense during the nine months ended December 31, 2012. This increase was due in part to the inclusion of Downeast in our results of operations for the full nine months ended December 31, 2013, as compared to only eight of the months in the nine month period ended December 31, 2012.

Operating Income. Our retail propane segment generated $15.7 million of operating income during the nine months ended December 31, 2013, compared to $9.8 million of operating income during the nine months ended December 31, 2012. The increase in operating income was due primarily to increased market demand due to colder weather conditions.

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.

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”).

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All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 0.5% to 1.5% per annum or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At December 31, 2013, the interest rate in effect on outstanding LIBOR borrowings was 1.92%, calculated as the LIBOR rate of 0.17% plus a margin of 1.75%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. At December 31, 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	$	460,000	1.92	%
Working Capital Facility —
LIBOR borrowings	348,500		1.92	%

At December 31, 2013, we were in compliance with all covenants under the Credit Agreement.

Senior Notes

At December 31, 2013, we were in compliance with all covenants under the Note Purchase Agreement and the Senior Notes.

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Unsecured Notes

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.

Revolving Credit Balances

The following table summarizes revolving credit facility borrowings during the nine months ended December 31, 2013 and 2012:

	Daily Average		Lowest		Highest
	Balance		Balance		Balance
	(in thousands)
Nine Months Ended December 31, 2013:
Expansion loans	$	366,796	$	—	$	546,000
Working capital loans	135,393		—		385,500

Nine Months Ended December 31, 2012:
New credit facility (June 19 - December 31)
Expansion loans	$	310,702	$	254,000	$	451,000
Working capital loans	112,622		70,000		153,500
Previous credit facility (April 1 - June 19)
Acquisition loans	222,238		186,000		239,275
Working capital loans	42,700		22,000		67,500

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Cash Flows

The following table summarizes the sources (uses) of our cash flows during the nine months ended December 31, 2013 and 2012:

	Nine Months Ended December 31,
	2013			2012
	(in thousands)
Cash Flows Provided by (Used In):
Operating activities, before changes in operating assets and liabilities	$	137,311		$	72,689
Changes in operating assets and liabilities	(72,135		)	(74,615		)

Operating activities	$	65,176		$	(1,926	)

Investing activities	(1,372,391		)	(514,842		)

Financing activities	1,304,555			532,839

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 lower operating income as a result of lower volumes of natural gas liquids sales and when we are building our inventory levels for the upcoming heating season. Our operating cash flows are generally greatest during our third and fourth fiscal quarters, or the six months ending March 31, when our operating income levels are highest and customers pay for natural gas liquids consumed during the heating season months. We borrow under our Revolving Credit Facility to supplement our operating cash flows as 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.

During the nine months ended December 31, 2013, we completed a number of business combinations for which we paid $1,240.6 million of cash, net of cash acquired, on a combined basis. Also during the nine months ended December 31, 2013, we paid $107.9 million for capital expenditures, which related primarily to water disposal and natural gas liquids terminal assets. Of this amount, $83.3 million represented expansion capital and $24.6 million represented maintenance capital.

During the nine months ended December 31, 2012, we completed our merger with High Sierra, for which we paid $239.3 million, net of cash acquired. Also during the nine months ended December 31, 2012, we completed twelve other acquisitions, for which we paid $254.0 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 nine months ended December 31, 2013, we borrowed $331.0 million on our Revolving Credit Facility (net of repayments) and issued $450.0 million of Unsecured Notes. During the nine months ended December 31, 2012, we borrowed $349.0 million on our revolving credit facilities (net of repayments) and issued $250.0 million of Senior Notes.

Cash flows from financing activities include proceeds from sales of equity. During the nine months ended December 31, 2013, we completed three equity issuances for which we received net proceeds of $650.2 million on a combined basis.

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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 December 31, 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 $26.8 million per quarter ($107.2 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
January 23, 2014	February 4, 2014	February 14, 2014	0.5313		42,150		4,283

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Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2013 for our fiscal years ending thereafter:

			Three Months
			Ending								After
			March 31,		Years Ending March 31,						March 31,
	Total		2014		2015		2016		2017		2017
	(in thousands)
Principal payments on long-term debt —
Expansion capital borrowings	$	460,000	$	—	$	—	$	—	$	—	$	460,000
Working capital borrowings	348,500		—		—		—		—		348,500
Senior notes	250,000		—		—		—		—		250,000
Unsecured Notes	450,000		—		—		—		—		450,000
Other long-term debt	16,818		2,100		6,924		3,669		2,315		1,810
Interest payments on long-term debt —
Revolving credit facility (1)	117,632		5,985		24,271		24,271		24,271		38,834
Senior notes	103,906		4,156		16,625		16,625		16,625		49,875
Unsecured Notes	247,500		—		30,938		30,938		30,938		154,686
Other long-term debt	1,367		134		388		219		126		500
Standby letters of credit	387,358		—		—		—		—		387,358
Future minimum lease payments under non-cancelable operating leases	545,111		39,151		134,876		110,868		73,341		186,875
Fixed price commodity purchase commitments	42,720		41,867		853		—		—		—
Index priced commodity purchase commitments (2)	1,004,530		779,949		195,921		28,660		—		—
Total contractual obligations	$	3,975,442	$	873,342	$	410,796	$	215,250	$	147,616	$	2,328,438

Natural gas liquids gallons under fixed-price purchase commitments (thousands) (3)	30,302		29,614		688		—		—		—
Natural gas liquids gallons under index-price purchase commitments (thousands) (3)	339,234		332,152		67,082		—		—		—
Crude oil barrels under index-price purchase commitments (thousands) (3)	4,773		3,453		963		357

(1) The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at December 31, 2013. See Note 7 to our condensed consolidated financial statements included in this Quarterly Report for additional information on our Credit Agreement.

(2) Index prices are based on a forward price curve at December 31, 2013. A theoretical change of $0.10 per gallon in the underlying commodity price at December 31, 2013 would result in a change of $39.9 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 December 31, 2013 would result in a change of approximately $4.8 million in the value of our index-based crude oil purchase commitments.

(3) At December 31, 2013, we had fixed priced and index-price sales contracts for 84.4 million and 324.1 million gallons of natural gas liquids, respectively. At December 31, 2013, we had index-price sales contracts for approximately 6.1 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 our condensed consolidated financial statements included 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.

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 increased 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. During the nine months ended December 31, 2013, spreads narrowed considerably, which had a significant impact on our operations in the Rocky Mountain and South Texas regions. When price differences between markets are reduced, it is necessary to renegotiate price terms with producers and to not fully utilize our transportation fleet until this process has been completed and margins have improved.

Water Solutions

Our opportunity to earn revenues in our water solutions business is based on the level of production of natural gas and crude oil in the areas where our facilities are located. 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 nine months ended December 31, 2013, we completed three separate acquisitions of water solutions businesses with operations in Texas. As a result, the geographic mix of our water solutions segment has changed, and we expect a greater share of the revenues from this segment to be generated from our operations in the Permian and Eagle Ford Basins in Texas than in the past.

During the nine months ended December 31, 2013, the revenues of our water solutions segment were approximately $3 million lower than our expectations and the operating expenses of our water solutions segment were approximately $2 million higher than our expectations. This related primarily to our operations in the Eagle Ford basin in Texas, which were obtained through several acquisitions during the nine months ended December 31, 2013. We have incurred higher than expected expenses, and have generated lower revenue than expected, in the process of bringing these operations up to the standards we have established for our water solutions business.

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. 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. Weather conditions during the current winter season have been much colder than normal. As a result, the demand for natural gas liquids has increased considerably, which has had a favorable impact on our sales volumes. The demand has also resulted in increases to market prices for natural gas liquids. This has had a favorable impact on product margins, based on the fact that we have purchased inventory when prices, and therefore our average cost of inventory, were lower than they are today. The natural gas liquids supply infrastructure has been strained due to the high level of demand. To this point we have been able to supply our existing retail and wholesale customers. The sharp rise in prices may increase the collectability risk of accounts receivable.

Retail Propane

The volumes we sell in our retail propane business are heavily dependent on weather conditions, as cold weather significantly increases customer demand for propane. During times of lower propane prices, margins per gallon typically increase. During times of higher propane prices, margins per gallon typically decrease. Weather conditions during the current winter season have been much colder than normal. As a result, the demand for natural gas liquids has increased considerably, which has had a favorable impact on our sales volumes. The demand has also resulted in increases to market prices for natural gas liquids. This has had a favorable impact on product margins, based on the fact that we have purchased inventory when prices, and therefore our average cost of inventory, were lower than they are today. The natural gas liquids supply infrastructure has been strained due to the high level of demand. To this point we have been able to supply our existing retail and wholesale customers. The sharp rise in prices may increase the collectability risk of accounts receivable, and the recent high prices may create downward pressure on future demand, as some customers may invest in making their homes more energy efficient or may take other steps to reduce their need for propane.

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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 our financial statements.

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

Revenue Recognition

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

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. 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. We have recorded an asset retirement obligation liability of $2.1 million at December 31, 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 assets. However, we do not believe the present value of these asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of our facilities, is material to our consolidated financial position or results of operations.

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

Depreciation expense represents the systematic 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 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 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 estimates also include the fair value of contracts, including commodity purchase and sale agreements, storage and transportation contracts, and employee compensation commitments. The excess of 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, crude oil, and refined products. 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

At December 31, 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.

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 at December 31, 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.

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. 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):

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	Increase
	(Decrease)
	To Fair Value
Crude oil (crude oil logistics segment)	$	(8,121	)
Crude oil (water solutions segment)	(4,782		)
Propane (natural gas liquids logistics segment)	1,982
Other products (natural gas liquids logistics segment)	1,393
Other	(889		)

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) 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 Securities and Exchange Commission 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 at December 31, 2013. Based on this evaluation, our principal executive officer and principal financial officer have concluded that at December 31, 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 nine months ended December 31, 2013, as discussed below, there have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)—15(f) of the Exchange Act) during the three months ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

We completed several business combinations during the year ended March 31, 2013 and during the nine months ended December 31, 2013, as described in Note 3 to our condensed consolidated financial statements included in this Quarterly Report. 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 structures 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

Set forth below are risk factors that are relevant to the operations of Gavilon Energy, which we acquired on December 2, 2013. Except as set forth below, 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.

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

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

· a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel, and travel;

· higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;

· an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers;

· an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for refined products and drive demand for alternative products; and

· the increased use of alternative fuel sources, such as battery-powered engines.

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

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

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

Certain of our operations are conducted through joint ventures. With respect to our joint ventures, we share ownership and management responsibilities with partners that may not share our goals and objectives. Differences in views among the partners may result in delayed decisions or failures to agree on major matters, such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, among others. Delay or failure to agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the joint venture. Accordingly, delayed decisions and disagreements could adversely

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affect the business and operations of the joint ventures and, in turn, our business and operations. From time to time, our joint ventures may be involved in disputes or legal proceedings which may negatively affect our investments. Accordingly, any such occurrences could adversely affect our financial condition, operating results and cash flows.

A change in the jurisdictional characterization of some of our joint venture’s assets by federal, state or local regulatory agencies, or a change in policy by those agencies, could result in increased regulation of such assets, which could affect the joint venture’s or our results of operations.

Intrastate transportation and gathering pipelines that do not provide interstate services are not subject to regulation by the Federal Energy Regulatory Commission (“FERC”). However, the distinction between FERC-regulated interstate pipeline transportation on the one hand and intrastate pipeline transportation on the other hand, is a fact-based determination. The classification and regulation of our crude oil pipelines are subject to change based on future determinations by the FERC, federal courts, Congress or regulatory commissions, courts or legislatures in the states in which we operate. Glass Mountain Pipeline, LLC (“Glass Mountain”), a joint venture, owns a pipeline in Oklahoma that we expect to use to carry crude oil owned by us and by third parties. We believe that the pipeline segments on which Glass Mountain would provide service to third parties and the services it would provide to third parties on this pipeline system meet the traditional tests that the FERC has used to determine that the pipeline services provided are not in interstate commerce. However, we cannot provide assurance that the FERC will not in the future, either at the request of other entities or on its own initiative, determine that some or all of the pipeline and the services Glass Mountain will provide on that system are within its jurisdiction, or that such a determination would not adversely affect Glass Mountain’s or our results of operations.

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

On December 2, 2013, we issued and sold 8,110,848 common units representing limited partnership interests in NGL in a private placement at a price of $29.59 per common unit for aggregate consideration of $240.0 million. This sale of common units was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof, as a transaction by an issuer not involving any public offering.

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			Equity Interest Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP, High Sierra Energy, LP, Gavilon, LLC and Gavilon Energy Intermediate, 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 December 5, 2013)
4.1			Indenture, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee (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 16, 2013)
4.2			Forms of 6.875% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)
4.3			Registration Rights Agreement, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors listed therein on Exhibit A and RBC Capital Markets, LLC as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)
4.4			Amendment No. 4 to Note Purchase Agreement, dated as of November 5, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8, 2013)
4.5			Registration Rights Agreement, dated December 2, 2013, by and among NGL Energy Partners LP and the purchasers set forth on Schedule A 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 December 5, 2013)
4.6			Amendment No. 5 to Note Purchase Agreement, dated as of December 23, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 31, 2013)
10.1			Amendment No. 4 to Credit Agreement, dated as of November 5, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8, 2013)
10.2			Common Unit Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP and the purchasers listed on Schedule A thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 5, 2013)
10.3			Amendment No. 5 to Credit Agreement, dated as of December 23, 2013, among NGL Energy Operating, LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank and Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 31, 2013)
10.4			Facility Increase Agreement among NGL Energy Operating, LLC, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 3, 2014)
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 at December 31, 2013 and March 31, 2013, (ii) Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2013 and 2012, (iii) Condensed Consolidated Statements of Comprehensive Income for the three months and nine months ended December 31, 2013 and 2012, (iv) Condensed Consolidated Statement of Changes in Partners’ Equity for the nine months ended December 31, 2013, (v) Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 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: February 10, 2014		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer


Date: February 10, 2014		By:	/s/ Atanas H. Atanasov
			Atanas H. Atanasov
			Chief Financial Officer

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EXHIBIT INDEX

Exhibit Number			Exhibit

2.1			Equity Interest Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP, High Sierra Energy, LP, Gavilon, LLC and Gavilon Energy Intermediate, 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 December 5, 2013)
4.1			Indenture, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee (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 16, 2013)
4.2			Forms of 6.875% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)
4.3			Registration Rights Agreement, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors listed therein on Exhibit A and RBC Capital Markets, LLC as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)
4.4			Amendment No. 4 to Note Purchase Agreement, dated as of November 5, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8, 2013)
4.5			Registration Rights Agreement, dated December 2, 2013, by and among NGL Energy Partners LP and the purchasers set forth on Schedule A 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 December 5, 2013)
4.6			Amendment No. 5 to Note Purchase Agreement, dated as of December 23, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 31, 2013)
10.1			Amendment No. 4 to Credit Agreement, dated as of November 5, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8, 2013)
10.2			Common Unit Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP and the purchasers listed on Schedule A thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 5, 2013)
10.3			Amendment No. 5 to Credit Agreement, dated as of December 23, 2013, among NGL Energy Operating, LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank and Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 31, 2013)
10.4			Facility Increase Agreement among NGL Energy Operating, LLC, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 3, 2014)
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.