NGL Energy Partners LP - Quarter Report: 2014 December (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended December 31, 2014

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

For the transition period from to

Commission File Number: 001-35172

NGL Energy Partners LP

(Exact Name of Registrant as Specified in Its Charter)

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

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

(918) 481-1119

(Registrant’s Telephone Number, Including Area Code)

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

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

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

Large accelerated filer x		Accelerated filer o

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 2, 2015, there were 89,723,169 common units issued and outstanding.

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PART I
Item 1.	Financial Statements (Unaudited)	3

	Condensed Consolidated Balance Sheets at December 31, 2014 and March 31, 2014	3
	Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2014 and 2013	4
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and nine months ended December 31, 2014 and 2013	5
	Condensed Consolidated Statement of Changes in Equity for the nine months ended December 31, 2014	6
	Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2014 and 2013	7
	Notes to Condensed Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	53
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	92
Item 4.	Controls and Procedures	93

PART II

Item 1.	Legal Proceedings	94
Item 1A.	Risk Factors	94
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	94
Item 3.	Defaults Upon Senior Securities	94
Item 4.	Mine Safety Disclosures	94
Item 5.	Other Information	94
Item 6.	Exhibits	95

Signatures		96

Exhibit Index		97

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Forward-Looking Statements

This Quarterly Report on Form 10-Q (“Quarterly Report”) 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,” “believe,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “plan,” “project,” “will,” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our general partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that impact 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 and distillates relative to the price of alternative and competing fuels;

· the price of gasoline relative to the price of corn, which impacts the price of ethanol;

· 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 drilling and production in producing basins in which we have water treatment and disposal 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 supply and demand for crude oil, natural gas liquids, refined products, ethanol, and biodiesel;

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

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

· availability, price, and marketing of competitive fuels;

· the impact of energy conservation efforts on product demand;

· energy efficiencies and technological trends;

· governmental regulation and taxation;

· the impact of legislative and regulatory actions on hydraulic fracturing and on the treatment of flowback and produced water;

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· 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;

· the loss of key personnel;

· the ability to hire drivers;

· the ability to renew contracts with key customers;

· the ability to maintain or increase the margins we realize for our terminal, barging, trucking and water disposal, and recycling and discharge services;

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

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

· the nonpayment or nonperformance by our customers;

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

· a deterioration of the credit and capital markets;

· the ability to successfully identify and consummate strategic acquisitions on economically favorable terms that are accretive to our financial results;

· the ability to successfully integrate acquired assets and businesses;

· changes in the volume of crude oil recovered during the wastewater treatment process;

· 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;

· the costs and effects of legal and administrative proceedings;

· any reduction or the elimination of the Renewable Fuels Standard;

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

· changes in the jurisdictional characteristics of, or the applicable regulatory policies with respect to, our 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, 2014, and as supplemented and updated by Part II, Item 1A “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2014.

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PART I

Item 1. Financial Statements (Unaudited)

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Balance Sheets

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

	December 31,			March 31,
	2014			2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	30,556		$	10,440
Accounts receivable - trade, net of allowance for doubtful accounts of $3,293 and $2,822, respectively	1,664,039			900,904
Accounts receivable - affiliates	42,549			7,445
Inventories	535,928			310,160
Prepaid expenses and other current assets	184,675			80,350
Total current assets	2,457,747			1,309,299

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $181,198 and $109,564, respectively	1,472,295			829,346
GOODWILL	1,250,239			1,107,006
INTANGIBLE ASSETS, net of accumulated amortization of $191,364 and $116,728, respectively	1,153,028			714,956
INVESTMENTS IN UNCONSOLIDATED ENTITIES	478,444			189,821
OTHER NONCURRENT ASSETS	94,149			16,795
Total assets	$	6,905,902		$	4,167,223

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable - trade	$	1,534,568		$	740,211
Accounts payable - affiliates	12,766			76,846
Accrued expenses and other payables	277,304			141,690
Advance payments received from customers	72,075			29,965
Current maturities of long-term debt	4,455			7,080
Total current liabilities	1,901,168			995,792

LONG-TERM DEBT, net of current maturities	2,753,322			1,629,834
OTHER NONCURRENT LIABILITIES	11,811			9,744

COMMITMENTS AND CONTINGENCIES

EQUITY, per accompanying statement:
General partner, representing a 0.1% interest, 88,634 and 79,420 notional units at December 31, 2014 and March 31, 2014, respectively	(39,035		)	(45,287		)
Limited partners, representing a 99.9% interest -
Common units, 88,545,764 and 73,421,309 units issued and outstanding at December 31, 2014 and March 31, 2014, respectively	1,709,150			1,570,074
Subordinated units, 5,919,346 units issued and outstanding at March 31, 2014	—			2,028
Accumulated other comprehensive loss	(89		)	(236		)
Noncontrolling interests	569,575			5,274
Total equity	2,239,601			1,531,853
Total liabilities and equity	$	6,905,902		$	4,167,223

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Operations

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

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2014			2013			2014			2013
REVENUES:
Crude oil logistics	$	1,694,881		$	1,316,060		$	5,735,307		$	3,260,862
Water solutions	50,241			41,772			150,274			96,475
Liquids	685,096			800,917			1,700,006			1,646,750
Retail propane	139,765			161,537			286,025			293,134
Refined products and renewables	1,983,444			306,600			5,708,161			306,600
Other	(1,281		)	116,559			1,513			119,518
Total Revenues	4,552,146			2,743,445			13,581,286			5,723,339

COST OF SALES:
Crude oil logistics	1,697,374			1,300,911			5,678,725			3,202,265
Water solutions	(29,085		)	2,571			(27,951		)	6,936
Liquids	657,010			745,894			1,633,090			1,555,539
Retail propane	81,172			105,394			168,590			181,956
Refined products and renewables	1,905,021			306,350			5,570,185			306,350
Other	176			114,909			2,547			114,909
Total Cost of Sales	4,311,668			2,576,029			13,025,186			5,367,955

OPERATING COSTS AND EXPENSES:
Operating	97,761			68,921			262,616			171,572
Loss on disposal of assets, net	30,073			340			34,639			2,503
General and administrative	44,230			21,492			113,742			54,258
Depreciation and amortization	50,335			35,494			139,809			83,279
Operating Income	18,079			41,169			5,294			43,772

OTHER INCOME (EXPENSE):
Earnings of unconsolidated entities	1,242			—			7,504			—
Interest expense	(30,051		)	(16,745		)	(79,196		)	(38,427		)
Other income, net	3,371			154			2,363			623
Income (Loss) Before Income Taxes	(7,359		)	24,578			(64,035		)	5,968

INCOME TAX (PROVISION) BENEFIT	2,090			(526		)	2,977			(356		)

Net Income (Loss)	(5,269		)	24,052			(61,058		)	5,612

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER	(11,783		)	(4,260		)	(32,220		)	(8,399		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(5,649		)	(154		)	(9,059		)	(288		)

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	(22,701	)	$	19,638		$	(102,337	)	$	(3,075	)

BASIC AND DILUTED INCOME (LOSS) PER COMMON UNIT	$	(0.26	)	$	0.27		$	(1.17	)	$	(0.03	)

BASIC AND DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	88,545,764			67,941,726			83,702,571			58,222,924

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)

(U.S. Dollars in Thousands)

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2014			2013			2014			2013

Net income (loss)	$	(5,269	)	$	24,052		$	(61,058	)	$	5,612
Other comprehensive income (loss)	(16		)	(100		)	147			(130		)
Comprehensive income (loss)	$	(5,285	)	$	23,952		$	(60,911	)	$	5,482

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statement of Changes in Equity

Nine Months Ended December 31, 2014

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

													Accumulated
				Limited Partners									Other
	General			Common				Subordinated					Comprehensive			Noncontrolling			Total
	Partner			Units	Amount			Units		Amount			Loss			Interests			Equity
BALANCES AT MARCH 31, 2014	$	(45,287	)	73,421,309	$	1,570,074		5,919,346		$	2,028		$	(236	)	$	5,274		$	1,531,853
Distributions	(26,376		)	—	(142,927		)	—		(6,748		)	—			(17,497		)	(193,548		)
Contributions	408			—	—			—		—			—			—			408
Sales of units, net of issuance costs	—			8,767,100	370,376			—		—			—			—			370,376
Equity issued pursuant to incentive compensation plan	—			438,009	18,684			—		—			—			—			18,684
Business combinations	—			—	—			—		—			—			572,895			572,895
Net income (loss)	32,220			—	(98,324		)	—		(4,013		)	—			9,059			(61,058		)
Other comprehensive income	—			—	—			—		—			147			—			147
Conversion of subordinated units to common units	—			5,919,346	(8,733		)	(5,919,346	)	8,733			—			—			—
Other	—			—	—			—		—			—			(156		)	(156		)
BALANCES AT DECEMBER 31, 2014	$	(39,035	)	88,545,764	$	1,709,150		—		$	—		$	(89	)	$	569,575		$	2,239,601

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Cash Flows

(U.S. Dollars in Thousands)

	Nine Months Ended
	December 31,
	2014			2013
OPERATING ACTIVITIES:
Net income (loss)	$	(61,058	)	$	5,612
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization, including debt issuance cost amortization	152,228			89,851
Non-cash equity-based compensation expense	13,384			10,840
Loss on disposal of assets, net	34,639			2,503
Provision for doubtful accounts	2,398			2,112
Commodity derivative (gain) loss	(240,992		)	26,711
Earnings of unconsolidated entities	(7,504		)	—
Distributions of earnings from unconsolidated entities	9,073			—
Other	5,275			(318		)
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable - trade	(574,658		)	(160,169		)
Accounts receivable - affiliates	(34,576		)	19,072
Inventories	154,607			(165,116		)
Prepaid expenses and other assets	(50,510		)	(5,811		)
Accounts payable - trade	679,945			203,934
Accounts payable - affiliates	(64,149		)	8,592
Accrued expenses and other liabilities	24,314			(2,046		)
Advance payments received from customers	39,424			29,006
Net cash provided by operating activities	81,840			64,773

INVESTING ACTIVITIES:
Purchases of long-lived assets	(135,435		)	(107,945		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	(1,114,045		)	(1,240,175		)
Cash flows from commodity derivatives	190,455			(30,659		)
Proceeds from sales of assets	15,236			7,302
Investments in unconsolidated entities	(33,528		)	(2,000		)
Distributions of capital from unconsolidated entities	8,736			1,591
Other investments	(45,855		)	—
Other	(66		)	(102		)
Net cash used in investing activities	(1,114,502		)	(1,371,988		)

FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	3,096,700			2,040,500
Payments on revolving credit facilities	(2,604,700		)	(1,709,500		)
Issuances of notes	400,000			450,000
Proceeds from borrowings on other long-term debt	—			880
Payments on other long-term debt	(5,476		)	(6,713		)
Debt issuance costs	(10,826		)	(24,061		)
Contributions	408			2,736
Distributions to partners	(176,051		)	(98,657		)
Distributions to noncontrolling interest owners	(17,497		)	(840		)
Proceeds from sale of common units, net of offering costs	370,376			650,210
Other	(156		)	—
Net cash provided by financing activities	1,052,778			1,304,555
Net increase (decrease) in cash and cash equivalents	20,116			(2,660		)
Cash and cash equivalents, beginning of period	10,440			11,561
Cash and cash equivalents, end of period	$	30,556		$	8,901

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Note 1 — Organization and Operations

NGL Energy Partners LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At December 31, 2014, our operations include:

· Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals, pipeline injection stations, a fleet of trucks, a fleet of leased and owned railcars, a fleet of barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

· Our water solutions segment, the assets of which include water treatment and disposal facilities. Our water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, from the sale of recycled water and recovered hydrocarbons, and from the disposal of tank bottoms and drilling mud.

· Our liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada, and which provides natural gas liquids terminaling services through its more than 20 owned terminals throughout the United States and railcar transportation services through its fleet of leased and owned railcars. Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the products to retailers, refiners, petrochemical plants, and other participants in the wholesale markets.

· Our retail propane segment, 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 25 states.

· Our refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the 2.0% general partner interest and a 19.7% limited partner interest in TransMontaigne Partners L.P. (“TLP”), which conducts refined products terminaling operations. TLP also owns a 42.5% interest in Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and a 50% interest in Frontera Brownsville LLC (“Frontera”), which are entities that own refined products storage facilities.

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, 2014 and 2013 include our accounts and those of our controlled subsidiaries. Investments where we do not have the ability to exercise control, but do have the ability to exercise significant influence, are accounted for using the equity method of accounting. All significant intercompany transactions and account balances have been eliminated in consolidation. The unaudited condensed consolidated balance sheet at March 31, 2014 is derived from audited financial statements. We have made certain reclassifications to prior period financial statements to conform to classification methods used in fiscal year 2015. These reclassifications had no impact on previously reported amounts of equity or net income.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim consolidated financial information in accordance with the rules and regulations of the Securities and Exchange Commission. The unaudited condensed consolidated financial statements include all adjustments that we consider necessary for a fair presentation of our consolidated financial position and results of operations for the interim periods presented. Such adjustments consist of only normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed consolidated financial statements do not include all the information and notes required by GAAP for complete annual consolidated financial statements. However, we believe that the disclosures made are adequate to make the information presented not misleading. These interim unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements for the fiscal year ended March 31, 2014 included in our Annual Report on Form 10-K (“Annual Report”). Due to the seasonal nature of our liquids and retail propane operations and other factors, the results of operations for interim periods are not necessarily indicative of the results to be expected for a future periods or for the full fiscal year ending March 31, 2015.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Use of Estimates

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

Significant Accounting Policies

Our significant accounting policies are consistent with those disclosed in Note 2 of our audited consolidated financial statements included in our Annual Report.

Revenue Recognition

We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. We record terminaling, transportation, storage, and service revenues at the time the service is performed, and we record tank and other rentals over the term of the lease. Pursuant to terminaling services agreements with certain of our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Such measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the product gained. Revenues for our water solutions segment are recognized upon receipt of the wastewater at our treatment and 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 our condensed consolidated statements of operations.

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

Fair Value Measurements

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

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

· 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. We determine the fair value of all our derivative financial instruments utilizing pricing models for significantly similar instruments. Inputs to the pricing model include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

· Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

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,
	2014		2013		2014		2013
	(in thousands)
Interest paid, exclusive of debt issuance costs and letter of credit fees	$	28,927	$	6,821	$	65,356	$	23,729
Income taxes paid	$	303	$	475	$	2,549	$	1,125

Value of common units issued in business combinations	$	—	$	—	$	—	$	80,619

Cash flows from settlements of commodity derivative instruments are classified as cash flows from investing activities in the condensed consolidated statements of cash flows, and adjustments to the fair value of commodity derivative instruments are included in the reconciliation of net income (loss) to net cash provided by operating activities.

Inventories

We value our inventories at the lower of cost or market, with cost determined using either the weighted-average cost or the first in, first out (FIFO) methods, including the cost of transportation and storage. Market is determined based on estimated replacement cost using prices at the end of the period. 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.

Inventories consist of the following:

	December 31,		March 31,
	2014		2014
	(in thousands)
Crude oil	$	68,749	$	156,473
Natural gas liquids —
Propane	184,583		85,159
Butane	25,468		15,106
Other	19,176		3,945
Refined products —
Gasoline	118,479		15,597
Diesel	68,584		7,612
Renewables	36,277		11,778
Other	14,612		14,490
Total	$	535,928	$	310,160

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Investments in Unconsolidated Entities

In December 2013, as part of our acquisition of Gavilon, LLC (“Gavilon Energy”), we acquired a 50% interest in Glass Mountain Pipeline, LLC (“Glass Mountain”) and an interest in a limited liability company that owns an ethanol production facility in the Midwest. In June 2014, we acquired an interest in a limited liability company that operates a water supply company in the DJ Basin. On July 1, 2014, as part of our acquisition of TransMontaigne Inc. (“TransMontaigne”), we acquired the general partner interest and a 19.7% limited partner interest in TLP, which owns a 42.5% interest in BOSTCO and a 50% interest in Frontera. We account for these investments using the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on our condensed consolidated balance sheets; instead, our ownership interests are reported within investments in unconsolidated entities on our condensed consolidated balance sheets. Under the equity method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions paid, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the historical net book value of the net assets of the investee.

Our investments in unconsolidated entities consist of the following:

		December 31,		March 31,
Entity	Segment	2014		2014
		(in thousands)
Glass Mountain (1)	Crude oil logistics	$	188,190	$	181,488
BOSTCO (2)	Refined products and renewables	236,938		—
Frontera	Refined products and renewables	23,755		—
Water supply company	Water solutions	16,500		—
Ethanol production facility	Refined products and renewables	13,061		8,333
Total		$	478,444	$	189,821

(1) When we acquired Gavilon Energy, we recorded the investment in Glass Mountain at fair value. The fair value of our investment in Glass Mountain exceeds our share of the historical net book value of Glass Mountain’s net assets by approximately $70 million. This difference relates primarily to goodwill and customer relationships.

(2) When we acquired TransMontaigne, we recorded the investment in BOSTCO at fair value. The fair value of our investment in BOSTCO exceeds our share of the historical net book value of BOSTCO’s net assets by approximately $11.8 million.

Other Noncurrent Assets

Other noncurrent assets consist of the following:

	December 31,		March 31,
	2014		2014
	(in thousands)
Capital lease (1)	$	45,855	$	—
Linefill (2)	30,868		—
Other	17,426		16,795
Total	$	94,149	$	16,795

(1) Represents a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party.

(2) Represents minimum volumes of product we are required to leave in third-party owned pipelines under long-term shipment commitments. At December 31, 2014, linefill consisted of approximately 404,000 barrels of crude oil with an average cost basis of $76.41 per barrel.

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following:

	December 31,		March 31,
	2014		2014
	(in thousands)
Accrued compensation and benefits	$	55,950	$	45,006
Derivative liabilities	62,591		42,214
Product exchange liabilities	24,448		3,719
Accrued interest	21,606		18,668
Income and other tax liabilities	64,123		13,421
Other	48,586		18,662
Total	$	277,304	$	141,690

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Business Combination Measurement Period

We record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination. As described in Note 4, certain of our acquisitions are still within this measurement period, and as a result, the acquisition date fair values we have recorded for the assets acquired and liabilities assumed are subject to change. Also as described in Note 4, we made certain adjustments during the nine months ended December 31, 2014 to our estimates of the acquisition date fair values of assets acquired and liabilities assumed in business combinations that occurred during the year ended March 31, 2014.

Noncontrolling Interests

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

On July 1, 2014, as part of our acquisition of TransMontaigne, we acquired a 19.7% limited partner interest in TLP. We have attributed net earnings allocable to TLP’s limited partners to the controlling and noncontrolling interests based on the relative ownership interests in TLP as well as including certain adjustments related to our acquisition accounting. Earnings allocable to TLP’s limited partners are net of the earnings allocable to TLP’s general partner interest. The earnings allocable to TLP’s general partner interest include the distributions of available cash (as defined by TLP’s partnership agreement) attributable to the period to TLP’s general partner interest and incentive distribution rights, net of adjustments for TLP’s general partner’s share of undistributed earnings. Undistributed earnings are allocated to TLP’s limited partners and TLP’s general partner interest based on their respective sharing of earnings or losses specified in TLP’s partnership agreement, which is based on their ownership percentages of 98% and 2%, respectively.

Note 3 — Earnings Per Unit

Our earnings per common unit were computed as follows:

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2014			2013			2014			2013
	(in thousands, except unit and per unit amounts)
Net income (loss) attributable to parent equity	$	(10,918	)	$	23,898		$	(70,117	)	$	5,324
Less: Net income allocated to general partner (1)	(11,783		)	(4,260		)	(32,220		)	(8,399		)
Less: Net loss (income) allocated to subordinated unitholders (2)	—			(1,353		)	4,013			1,295
Net income (loss) allocated to common unitholders	$	(22,701	)	$	18,285		$	(98,324	)	$	(1,780	)

Weighted average common units outstanding	88,545,764			67,941,726			83,702,571			58,222,924

Income (loss) per common unit - basic and diluted	$	(0.26	)	$	0.27		$	(1.17	)	$	(0.03	)

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

(2) All outstanding subordinated units converted to common units in August 2014. Since the subordinated units did not share in the distribution of cash generated during the three months ended September 30, 2014, we did not allocate any earnings or loss during this period to the subordinated unitholders. During the three months ended June 30, 2014 and the nine months ended December 31, 2013, 5,919,346 subordinated units were outstanding. The income (loss) per subordinated unit was ($0.68) for the three months ended June 30, 2014, $0.23 for the three months ended December 31, 2013, and $(0.22) for the nine months ended December 31, 2013.

The restricted units described in Note 10 were antidilutive during the three months and nine months ended December 31, 2014 and 2013, but could impact earnings per unit in future periods.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Note 4 — Acquisitions

Year Ending March 31, 2015

Grand Mesa Pipeline, LLC

In September 2014, we entered into a joint venture with RimRock Midstream, LLC (“RimRock”) whereby each party owned a 50% interest in Grand Mesa Pipeline, LLC (“Grand Mesa”). Grand Mesa is constructing a crude oil pipeline originating in Weld County, Colorado and terminating at our Cushing, Oklahoma terminal. In October 2014, Grand Mesa completed a successful open season in which it received the requisite support, in the form of ship-or-pay volume commitments from multiple shippers, to begin construction of the pipeline system. In November 2014, we acquired RimRock’s 50% ownership interest in Grand Mesa for $310.0 million in cash and preliminarily allocated this to a customer commitment intangible asset. We anticipate that the pipeline will commence service in late 2016, at which time we will begin to amortize this intangible asset.

Bakken Water Solutions Facilities

On November 21, 2014, we completed the acquisition of two saltwater disposal facilities in the Bakken Basin in North Dakota for $34.6 million of cash.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in this business combination. The estimates of fair value reflected at December 31, 2014 are subject to change. We expect to complete this process prior to finalizing our financial statements for the quarter ending September 30, 2015. We have preliminarily estimated the fair values of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Property, plant and equipment:
Water treatment facilities and equipment (5—40 years)	$	3,957
Buildings and leasehold improvements (3—7 years)	118
Other (7 years)	145
Goodwill	30,448
Other noncurrent liabilities	(68		)
Fair value of net assets acquired	$	34,600

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

The operations of these water disposal facilities have been included in our condensed consolidated statement of operations since their acquisition date. Our condensed consolidated statement of operations for the three months and nine months ended December 31, 2014 includes revenues of $1.0 million and operating income of $0.7 million that were generated by the operations of these water disposal facilities.

TransMontaigne Inc.

On July 1, 2014, we acquired TransMontaigne for $200.3 million of cash, net of cash acquired (including $174.1 million paid at closing and $26.2 million paid upon completion of the working capital settlement). As part of this transaction, we also purchased $380.4 million of inventory from the previous owner of TransMontaigne (including $346.9 million paid at closing and $33.5 million subsequently paid as the working capital settlement process progressed). The operations of TransMontaigne include the marketing of refined products. As part of this transaction, we acquired the 2.0% general partner interest, the incentive distribution rights, and a 19.7% limited partner interest in TLP, and assumed certain terminaling service agreements with TLP from an affiliate of the previous owner of TransMontaigne.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in this business combination. The estimates of fair value reflected at December 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the three months ending June 30, 2015.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

We have preliminarily estimated the fair values of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Cash and cash equivalents	$	1,469
Accounts receivable - trade	197,554
Accounts receivable - affiliates	528
Inventories	379,512
Prepaid expenses and other current assets	15,082
Property, plant and equipment:
Refined products terminal assets and equipment (20 years)	376,587
Vehicles	1,565
Crude oil tanks and related equipment (20 years)	28,666
Information technology equipment	7,851
Buildings and leasehold improvements (20 years)	10,339
Land	67,910
Tank bottoms	46,900
Other	12,592
Construction in progress	4,487
Goodwill (1)	38,576
Intangible assets:
Customer relationships (15 years)	76,100
Pipeline capacity rights (30 years)	87,618
Trade names (indefinite life)	5,000
Investments in unconsolidated entities	245,400
Other noncurrent assets	3,911
Accounts payable - trade	(113,345		)
Accounts payable - affiliates	(69		)
Accrued expenses and other payables	(77,260		)
Advance payments received from customers	(1,919		)
Long-term debt	(234,000		)
Other noncurrent liabilities	(33,227		)
Noncontrolling interests	(567,120		)
Fair value of net assets acquired	$	580,707

(1) Included in the refined products and renewables segment.

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

The intangible asset for pipeline capacity rights relates to capacity allocations on a third-party refined products pipeline. Demand for use of this pipeline exceeds the pipeline’s capacity, and the limited capacity is allocated based on a shipper’s historical shipment volumes.

The fair value of the noncontrolling interests was calculated by multiplying the closing price of TLP’s common units on the acquisition date by the number of TLP common units held by parties other than us.

We recorded in the acquisition accounting a liability of $2.5 million related to certain crude oil contracts with terms that were unfavorable at current market conditions. We amortized this balance to cost of sales during the three months ended September 30, 2014.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Employees of TransMontaigne participate in a plan whereby they are entitled to certain termination benefits in the event of a change in control of TransMontaigne and a subsequent change in job status. We recorded expense of $6.0 million and $8.7 million during the three months and nine months ended December 31, 2014, respectively, related to these termination benefits, and we may record additional expense in future quarters as we continue our integration efforts.

The operations of TransMontaigne have been included in our condensed consolidated statements of operations since TransMontaigne was acquired on July 1, 2014. Our condensed consolidated statement of operations for the nine months ended December 31, 2014 includes revenues of $3.0 billion and operating income of $16.7 million that were generated by the operations of TransMontaigne. We have not provided supplemental pro forma financial information as though the business combination had occurred on April 1, 2013. The previous owner of TransMontaigne conducted trading operations, whereas we strive to generate reliable and predictable cash flows. Because of the difference in strategies between the pre-acquisition and post-acquisition periods, the pre-acquisition operations of TransMontaigne have limited importance as an indicator of post-acquisition results.

Water Solutions Facilities

As described below, we are party to a development agreement that provides us a right to purchase water treatment and disposal facilities developed by the other party to the agreement. During the nine months ended December 31, 2014, we purchased 11 water treatment and disposal facilities under this development agreement. We also purchased a 75% interest in one additional water treatment and disposal facility in July 2014 from a different seller. On a combined basis, we paid $161.0 million of cash for these 12 facilities.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these business combinations. The estimates of fair value reflected at December 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the three months ending September 30, 2015. We have preliminarily estimated the fair values of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	939
Inventories	253
Prepaid expenses and other current assets	62
Property, plant and equipment:
Water treatment facilities and equipment (5—40 years)	58,222
Buildings and leasehold improvements (3—7 years)	6,009
Land	2,120
Other (7 years)	213
Goodwill	105,434
Other noncurrent assets	50
Accounts payable - trade	(58		)
Accrued expenses and other payables	(6,092		)
Other noncurrent liabilities	(352		)
Noncontrolling interest	(5,775		)
Fair value of net assets acquired	$	161,025

The operations of these water treatment and disposal facilities have been included in our condensed consolidated statement of operations since their acquisition date. Our condensed consolidated statement of operations for the nine months ended December 31, 2014 includes revenues of $16.6 million and operating income of $5.7 million that were generated by the operations of these facilities.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Retail Propane Acquisitions

During the nine months ended December 31, 2014, we completed seven acquisitions of retail propane businesses. On a combined basis, we paid $12.4 million of cash to acquire these assets and operations. The agreements for these acquisitions contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in certain of these business combinations, and as a result, the estimates of fair value reflected at December 31, 2014 are subject to change.

Water Supply Company

On June 9, 2014, we paid cash of $15.0 million in exchange for an interest in a water supply company operating in the DJ Basin. The company holds exclusive rights to construct water disposal facilities on a dedicated acreage. We account for this investment using the equity method of accounting.

Year Ended March 31, 2014

Gavilon Energy

On December 2, 2013, we completed a business combination in which we acquired Gavilon Energy. We paid $832.4 million of cash, net of cash acquired, in exchange for these assets and operations.

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

During the three months ended September 30, 2014, we completed the acquisition accounting for this business combination. The following table presents the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for this acquisition:

				Estimated
				at
				March 31,
	Final			2014			Change
	(in thousands)
Accounts receivable - trade	$	326,484		$	349,529		$	(23,045	)
Accounts receivable - affiliates	2,564			2,564			—
Inventories	107,430			107,430			—
Prepaid expenses and other current assets	68,322			68,322			—
Property, plant and equipment:
Vehicles (3 years)	327			791			(464		)
Crude oil tanks and related equipment (3—40 years)	83,797			77,429			6,368
Information technology equipment (3—7 years)	4,049			4,046			3
Buildings and leasehold improvements (3—40 years)	7,817			7,716			101
Land	6,427			6,427			—
Tank bottoms	16,930			15,230			1,700
Other (7 years)	162			170			(8		)
Construction in progress	7,180			7,190			(10		)
Goodwill (1)	342,769			359,169			(16,400		)
Intangible assets:
Customer relationships (10—20 years)	107,950			101,600			6,350
Lease agreements (1—5 years)	8,700			8,700			—
Pipeline capacity rights (30 years)	7,800			—			7,800
Investments in unconsolidated entities	183,000			178,000			5,000
Other noncurrent assets	2,287			9,918			(7,631		)
Accounts payable - trade	(342,792		)	(342,792		)	—
Accounts payable - affiliates	(2,585		)	(2,585		)	—
Accrued expenses and other payables	(49,447		)	(70,999		)	21,552
Advance payments received from customers	(10,667		)	(10,667		)	—
Other noncurrent liabilities	(46,056		)	(44,740		)	(1,316		)
Fair value of net assets acquired	$	832,448		$	832,448		$	—

(1) Of this goodwill, $302.8 million was allocated to our crude oil logistics segment, $36.0 million was allocated to our refined products and renewables segment, and $4.0 million was allocated to our liquids segment.

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

The acquisition method of accounting requires that executory contracts that are at unfavorable terms relative to current market conditions at the acquisition date be recorded as assets or liabilities in the acquisition accounting. Since certain crude oil storage lease commitments were at unfavorable terms relative to acquisition date market conditions, we recorded a liability of $15.9 million related to these lease commitments in the acquisition accounting, and we amortized $6.9 million of this balance through cost of sales during the nine months ended December 31, 2014. We will amortize the remainder of this liability over the term of the leases. The future amortization of this liability is shown below (in thousands):

Year Ending March 31,
2015 (three months)	$	1,740
2016	4,040
2017	360

Certain personnel who were employees of Gavilon Energy were entitled to a bonus, half of which was payable upon successful completion of the business combination and the remainder of which was paid in December 2014. We recorded this as compensation expense over the vesting period. We recorded expense of $6.5 million during the nine months ended December 31, 2014 related to these bonuses.

Oilfield Water Lines, LP

On August 2, 2013, we completed a business combination with entities affiliated with Oilfield Water Lines LP (collectively, “OWL”), whereby we acquired water disposal and transportation assets in Texas. We issued 2,463,287 common units, valued at $68.6 million, and paid $167.7 million of cash, net of cash acquired, in exchange for OWL. During the three months ended June 30, 2014, we completed the acquisition accounting for this business combination. The following table presents the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for this acquisition:

				Estimated
				at
				March 31,
	Final			2014			Change
	(in thousands)
Accounts receivable - trade	$	6,837		$	7,268		$	(431	)
Inventories	154			154			—
Prepaid expenses and other current assets	402			402			—
Property, plant and equipment:
Vehicles (5—10 years)	8,143			8,157			(14		)
Water treatment facilities and equipment (3—30 years)	23,173			23,173			—
Buildings and leasehold improvements (7—30 years)	2,198			2,198			—
Land	710			710			—
Other (3—5 years)	53			53			—
Intangible assets:
Customer relationships (8—10 years)	110,000			110,000			—
Non-compete agreements (3 years)	2,000			2,000			—
Goodwill	90,144			89,699			445
Accounts payable - trade	(6,469		)	(6,469		)	—
Accrued expenses and other payables	(992		)	(992		)	—
Other noncurrent liabilities	(64		)	(64		)	—
Fair value of net assets acquired	$	236,289		$	236,289		$	—

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Other Water Solutions Acquisitions

During the year ended March 31, 2014, we completed two separate acquisitions of businesses to expand our water solutions operations in Texas. On a combined basis, we issued 222,381 common units, valued at $6.8 million, and paid $151.6 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. During the three months ended June 30, 2014, we completed the acquisition accounting for these business combinations. The following table presents the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these acquisitions:

				Estimated
				at
				March 31,
	Final			2014			Change
	(in thousands)
Accounts receivable - trade	$	2,146		$	2,146		$	—
Inventories	192			192			—
Prepaid expenses and other current assets	62			61			1
Property, plant and equipment:
Vehicles (5—10 years)	76			90			(14		)
Water treatment facilities and equipment (3—30 years)	11,717			14,394			(2,677		)
Buildings and leasehold improvements (7—30 years)	3,278			1,906			1,372
Land	207			206			1
Other (3—5 years)	12			12			—
Goodwill	49,067			47,750			1,317
Intangible assets:
Customer relationships (8—10 years)	72,000			72,000			—
Trade names (indefinite life)	3,325			3,325			—
Non-compete agreements (3 years)	260			260			—
Water facility development agreement (5 years)	14,000			14,000			—
Water facility option agreement	2,500			2,500			—
Accounts payable - trade	(119		)	(119		)	—
Accrued expenses and other payables	(293		)	(293		)	—
Other noncurrent liabilities	(64		)	(64		)	—
Fair value of net assets acquired	$	158,366		$	158,366		$	—

As part of one of these business combinations, we entered into an option agreement with the seller of the business whereby we had the option to purchase a saltwater disposal facility that was under construction. We recorded an intangible asset of $2.5 million at the acquisition date related to this option agreement. On March 1, 2014, we purchased the saltwater disposal facility for additional cash consideration of $3.7 million.

In addition, as part of one of these business combinations, we entered into a development agreement that provides us a right to purchase water treatment and disposal facilities that may be developed by the seller through June 2018. On March 1, 2014, we purchased our first water treatment and disposal facility pursuant to the development agreement for $21.0 million.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

During the three months ended December 31, 2014, we completed the acquisition accounting for these business combinations. The following table presents the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these acquisitions:

				Estimated
				at
				March 31,
	Final			2014			Change
	(in thousands)
Accounts receivable - trade	$	124		$	245		$	(121	)
Inventories	119			197			(78		)
Property, plant and equipment:
Water treatment facilities and equipment (3—30 years)	10,539			10,540			(1		)
Buildings and leasehold improvements (7—30 years)	1,130			1,130			—
Land	213			213			—
Other (3—5 years)	1			1			—
Goodwill	15,443			15,281			162
Accounts payable - trade	(232		)	(263		)	31
Accrued expenses and other payables	—			(7		)	7
Other noncurrent liabilities	(50		)	(50		)	—
Fair value of net assets acquired	$	27,287		$	27,287		$	—

Crude Oil Logistics Acquisitions

During the year ended March 31, 2014, we completed two separate acquisitions of businesses to expand our crude oil logistics operations in Texas and Oklahoma. On a combined basis, we issued 175,211 common units, valued at $5.3 million, and paid $67.8 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. During the three months ended June 30, 2014, we completed the acquisition accounting for these business combinations. The following table presents the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these acquisitions:

				Estimated
				at
				March 31,
	Final			2014			Change
	(in thousands)
Accounts receivable - trade	$	1,221		$	1,235		$	(14	)
Inventories	1,021			1,021			—
Prepaid expenses and other current assets	58			54			4
Property, plant and equipment:
Vehicles (5—10 years)	2,980			2,977			3
Buildings and leasehold improvements (5—30 years)	58			280			(222		)
Crude oil tanks and related equipment (2—30 years)	3,822			3,462			360
Barges and towboats (20 years)	20,065			20,065			—
Other (3—5 years)	57			53			4
Goodwill	30,730			37,867			(7,137		)
Intangible assets:
Customer relationships (3 years)	13,300			6,300			7,000
Non-compete agreements (3 years)	35			35			—
Trade names (indefinite life)	530			530			—
Accounts payable - trade	(521		)	(665		)	144
Accrued expenses and other payables	(266		)	(124		)	(142		)
Fair value of net assets acquired	$	73,090		$	73,090		$	—

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Retail Propane and Liquids Acquisitions

During the year ended March 31, 2014, we completed four acquisitions of retail propane businesses and the acquisition of four natural gas liquids terminals. On a combined basis, we paid $21.9 million of cash to acquire these assets and operations. During the three months ended December 31, 2014, we completed the acquisition accounting for these business combinations. The final calculation of the fair values of the assets acquired and liabilities assumed for these acquisitions did not materially change from the previous estimates of the fair values of the assets acquired and liabilities assumed for these acquisitions.

Note 5 — Property, Plant and Equipment

Our property, plant and equipment consists of the following:

	December 31,			March 31,
Description and Estimated Useful Lives	2014			2014
	(in thousands)
Natural gas liquids terminal assets (2—30 years)	$	75,850		$	75,141
Refined products terminal assets and equipment (20 years)	379,118			—
Retail propane equipment (2—30 years)	173,041			160,758
Vehicles and railcars (3—25 years)	177,056			152,676
Water treatment facilities and equipment (3—30 years)	264,918			180,985
Crude oil tanks and related equipment (2—40 years)	131,766			106,125
Barges and towboats (5—40 years)	58,579			52,217
Information technology equipment (3—7 years)	33,010			20,768
Buildings and leasehold improvements (3—40 years)	82,274			60,004
Land	101,789			30,241
Tank bottoms	64,594			13,403
Other (3—30 years)	34,669			6,341
Construction in progress	76,829			80,251
	1,653,493			938,910
Less: Accumulated depreciation	(181,198		)	(109,564		)
Net property, plant and equipment	$	1,472,295		$	829,346

Depreciation expense was $29.7 million and $15.6 million during the three months ended December 31, 2014 and 2013, respectively, and $76.6 million and $42.8 million during the nine months ended December 31, 2014 and 2013, respectively.

Product volumes required for the operation of storage tanks, known as tank bottoms, are recorded at historical cost. We recover tank bottoms when we no longer use the storage tanks or the storage tanks are removed from service. At December 31, 2014, tank bottoms consisted of approximately 185,000 barrels of crude oil with an average cost basis of $91.42 per barrel and approximately 16.8 million gallons of refined products with an average cost basis of $2.78 per gallon.

Note 6 — Goodwill and Intangible Assets

The changes in the balance of goodwill during the nine months ended December 31, 2014 were as follows (in thousands):

Balance at March 31, 2014	$	1,107,006
Revisions to acquisition accounting (Note 4)	(21,614		)
Acquisitions (Note 4)	174,829
Disposals	(9,982		)
Balance at December 31, 2014	$	1,250,239

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

During the nine months ended December 31, 2014, we sold a natural gas liquids terminal and a water transportation business. We allocated goodwill of $8.2 million and $1.8 million, respectively, to these transactions and recorded corresponding losses on disposal of these assets to our condensed consolidated statements of operations. We also recorded losses on property, plant and equipment of $21.7 million and $2.2 million, respectively, related to these disposals.

Goodwill by reportable segment is as follows:

	December 31,		March 31,
	2014		2014
	(in thousands)
Crude oil logistics	$	579,844	$	606,383
Water solutions	398,280		262,203
Liquids	82,950		90,135
Retail propane	114,588		114,285
Refined products and renewables	74,577		34,000
Total	$	1,250,239	$	1,107,006

Our intangible assets consist of the following:

		December 31, 2014				March 31, 2014
	Amortizable	Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Lives	Amount		Amortization		Amount		Amortization
		(in thousands)
Amortizable —
Customer relationships	3–20 years	$	789,418	$	136,824	$	697,405	$	83,261
Pipeline capacity rights	30 years	95,418		1,742		—		—
Water facility development agreement	5 years	14,000		4,200		14,000		2,100
Executory contracts and other agreements	2–10 years	23,920		17,387		23,920		13,190
Non-compete agreements	2–7 years	14,562		9,271		14,161		6,388
Trade names	2–10 years	14,539		6,752		15,489		3,081
Debt issuance costs	5–10 years	54,915		15,188		44,089		8,708
Total amortizable		1,006,772		191,364		809,064		116,728

Non-amortizable —
Customer commitments		310,000				—
Trade names		27,620				22,620
Total		$	1,344,392	$	191,364	$	831,684	$	116,728

The weighted-average remaining amortization period for intangible assets is approximately 12 years.

Amortization expense is as follows:

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
Recorded In	2014		2013		2014		2013
	(in thousands)
Depreciation and amortization	$	20,612	$	19,888	$	63,216	$	40,488
Cost of sales	1,818		943		5,939		2,517
Interest expense	2,451		1,593		6,480		4,055
Total	$	24,881	$	22,424	$	75,635	$	47,060

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Expected amortization of our intangible assets, exclusive of assets that are not yet amortizable, is as follows (in thousands):

Year Ending March 31,
2015 (three months)	$	24,626
2016	95,854
2017	89,131
2018	85,154
2019	77,831
Thereafter	442,812
Total	$	815,408

Note 7 — Long-Term Debt

Our long-term debt consists of the following:

	December 31,		March 31,
	2014		2014
	(in thousands)
Revolving credit facility —
Expansion capital borrowings	$	598,000	$	532,500
Working capital borrowings	798,000		389,500
5.125% Notes due 2019	400,000		—
6.875% Notes due 2021	450,000		450,000
6.650% Notes due 2022	250,000		250,000
TLP credit facility	252,000		—
Other long-term debt	9,777		14,914
	2,757,777		1,636,914
Less: Current maturities	4,455		7,080
Long-term debt	$	2,753,322	$	1,629,834

Credit Agreement

We have 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”). At December 31, 2014, our Revolving Credit Facility had a total capacity of $2.296 billion.

The Expansion Capital Facility had a total capacity of $858.0 million for cash borrowings at December 31, 2014. At that date, we had outstanding borrowings of $598.0 million on the Expansion Capital Facility. The Working Capital Facility had a total capacity of $1.438 billion for cash borrowings and letters of credit at December 31, 2014. At that date, we had outstanding borrowings of $798.0 million and outstanding letters of credit of $176.1 million on the Working Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base,” as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time.

The commitments under the Credit Agreement expire on November 5, 2018. We have the right to prepay outstanding borrowings under the Credit Agreement without incurring any penalties, and prepayments of principal may be required if we enter into certain transactions to sell assets or obtain new borrowings.

All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 0.50% to 1.50% per annum or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At December 31, 2014, all borrowings under the Credit Agreement were LIBOR borrowings with an interest rate at December 31, 2014 of 2.17%, calculated as the LIBOR rate of 0.17% plus

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

a margin of 2.0%. At December 31, 2014, the interest rate in effect on letters of credit was 2.0%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit.

The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our leverage ratio, as defined in the Credit Agreement, cannot exceed 4.25 to 1 at any quarter end. At December 31, 2014, our leverage ratio was approximately 3.3 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 at any quarter end. At December 31, 2014, our interest coverage ratio was approximately 5.6 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, 2014, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

On July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the “2019 Notes”) in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $393.5 million, after the initial purchasers’ discount of $6.0 million and offering costs of $0.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

The 2019 Notes mature on July 15, 2019. Interest is payable on January 15 and July 15 of each year. We have the right to redeem the 2019 Notes prior to the maturity date, although we would be required to pay a premium for early redemption.

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2019 Notes, and the obligations under the 2019 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The purchase agreement and the indenture governing the 2019 Notes contain various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

At December 31, 2014, we were in compliance with the covenants under the purchase agreement and indenture governing the 2019 Notes.

We also entered into a registration rights agreement whereby we have committed to exchange the 2019 Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the 2019 Notes. We expect to complete this exchange in February 2015.

2021 Notes

On October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the “2021 Notes”) in a private placement exempt from registration under the Securities Act pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $438.4 million, after the initial purchasers’ discount of $10.1 million and offering costs of $1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

At December 31, 2014, we were in compliance with the covenants under the purchase agreement and indenture governing the 2021 Notes.

We also entered into a registration rights agreement whereby we have committed to exchange the 2021 Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the 2021 Notes. We expect to complete this exchange in February 2015.

2022 Notes

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

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

The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary grace and cure periods): (i) nonpayment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the 2022 Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the Note Purchase Agreement, the 2022 Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregate principal amount of the then outstanding 2022 Notes of any series may declare all of the 2022 Notes of such series to be due and payable immediately.

At December 31, 2014, we were in compliance with the covenants under the Note Purchase Agreement.

TLP Credit Facility

On March 9, 2011, TLP entered into an amended and restated senior secured credit facility (“TLP Credit Facility”), which has been subsequently amended from time to time. The TLP Credit Facility provides for a maximum borrowing line of credit equal to the lesser of (i) $350 million or (ii) 4.75 times Consolidated EBITDA (as defined in the TLP Credit Facility). TLP may elect to have loans under the TLP Credit Facility that bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLP also pays a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.50% per annum, depending on the total leverage ratio then in effect. TLP’s obligations under the TLP Credit Facility are secured by a first priority security interest in favor of the lenders in the majority of TLP assets.

The terms of the TLP Credit Facility include covenants that restrict TLP’s ability to make cash distributions, acquisitions and investments, including investments in joint ventures. TLP may make distributions of cash to the extent of its “available cash” as defined in the TLP partnership agreement.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

The following table summarizes our basis in the assets and liabilities of TLP at December 31, 2014, inclusive of the impact of our acquisition accounting for the business combination with TransMontaigne (in thousands):

Cash and cash equivalents	$	3,304
Accounts receivable - trade, net	10,310
Accounts receivable - affiliates	408
Inventories	1,591
Prepaid expenses and other current assets	1,474
Property, plant and equipment, net	475,950
Goodwill	38,576
Intangible assets, net	1,933
Investments in unconsolidated affiliates	260,694
Other noncurrent assets	1,670
Accounts payable - trade	(6,985		)
Accounts payable - affiliates	(128		)
Accrued expenses and other payables	(9,691		)
Advanced payments received from customers	(144		)
Long-term debt	(252,000		)
Other noncurrent liabilities	(3,870		)
Net assets	$	523,092

Under the TLP Credit Facility, TLP may make acquisitions and investments that meet the definition of “permitted acquisitions” “other investments” which may not exceed 5% of “consolidated net tangible assets” and “permitted JV investments”. Permitted JV investments include up to $225 million of investments in BOSTCO, the “Specified BOSTCO Investment”. In addition to the Specified BOSTCO Investment, under the terms of the TLP Credit Facility, TLP may make an additional $75 million of other permitted JV investments (including additional investments in BOSTCO). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 9, 2016.

The TLP Credit Facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the TLP Credit Facility are (i) a total leverage ratio (not to exceed 4.75 to 1), (ii) a senior secured leverage ratio (not to exceed 3.75 to 1) in the event TLP issues senior unsecured notes, and (iii) a minimum interest coverage ratio (not less than 3.0 to 1).

If TLP were to fail any financial covenant, or any other covenant contained in the TLP Credit Facility, TLP would seek a waiver from its lenders under such facility. If TLP was unable to obtain a waiver from its lenders and the default remained uncured after any applicable grace period, TLP would be in breach of the TLP Credit Facility, and the lenders would be entitled to declare all outstanding borrowings immediately due and payable. TLP was in compliance with all of the financial covenants under the TLP Credit Facility as of December 31, 2014.

At December 31, 2014, TLP had $252.0 million of outstanding borrowings under the TLP Credit Facility and no outstanding letters of credit.

Other Long-Term Debt

We have executed various noninterest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also have certain notes payable related to equipment financing.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at December 31, 2014:

	Revolving								TLP		Other
	Credit		2019		2021		2022		Credit		Long-Term
Year Ending March 31,	Facility		Notes		Notes		Notes		Facility		Debt		Total
	(in thousands)
2015 (three months)	$	—	$	—	$	—	$	—	$	—	$	1,026	$	1,026
2016	—		—		—		—		252,000		3,187		255,187
2017	—		—		—		—		—		2,398		2,398
2018	—		—		—		25,000		—		1,505		26,505
2019	1,396,000		—		—		50,000		—		1,480		1,447,480
Thereafter	—		400,000		450,000		175,000		—		181		1,025,181
Total	$	1,396,000	$	400,000	$	450,000	$	250,000	$	252,000	$	9,777	$	2,757,777

Note 8 — Income Taxes

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

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

In December 2014 we converted TransMontaigne Inc. and certain of its subsidiaries from taxable corporations to non-taxable limited liability companies. Upon this conversion, the deferred tax liability associated with these entities became a current tax liability, and we reclassified $22.8 million from other noncurrent liabilities to accrued expenses and other payables on our consolidated balance sheet at December 31, 2014.

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

We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in the consolidated financial statements at December 31, 2014.

Note 9 — Commitments and Contingencies

Legal Contingencies

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Customer Dispute

A customer of our crude oil logistics segment disputed the transportation rate schedule we used to bill the customer for services that we provided from November 2012 through February 2013, which was the same rate schedule that Pecos Gathering & Marketing, L.L.C. and certain of its affiliated companies (collectively, “Pecos”), used to bill the customer from April 2011 through October 2012 (prior to our November 1, 2012 acquisition of Pecos). During August 2013, the customer notified us that it intended to withhold payment due for services performed by us during the period from June 2013 through August 2013, pending resolution of the dispute, although the customer did not dispute the validity of the amounts billed for services performed during this time frame.

During September 2014, we reached an agreement with the former customer whereby the former customer agreed to pay us an agreed-upon amount to dismiss its claims against us, in return for which we agreed to dismiss our claims against the former customer. We did not record a gain or loss upon settlement, as the amount we received approximated the amount we had recorded as receivable from the customer.

Contractual Dispute

During the three months ended December 31, 2014, we settled a contractual dispute and recorded $2.5 million of proceeds to other income in our condensed consolidated statements of operations.

Environmental Matters

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

Asset Retirement Obligations

We have recorded a liability of $3.1 million at December 31, 2014 for asset retirement obligations. This liability is related to water treatment and disposal facilities and crude oil facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment. Future minimum lease payments under these agreements at December 31, 2014 are as follows (in thousands):

Year Ending March 31,
2015 (three months)	$	34,633
2016	111,286
2017	93,153
2018	78,683
2019	54,323
Thereafter	127,977
Total	$	500,055

Rental expense relating to operating leases was $36.8 million and $23.3 million during the three months ended December 31, 2014 and 2013, respectively, and $91.4 million and $68.8 million during the nine months ended December 31, 2014 and 2013, respectively.

Pipeline Capacity Agreements

We have executed noncancelable agreements with crude oil and refined products pipeline operators, which guarantee us minimum monthly shipping capacity on the pipelines. In exchange, we are obligated to pay the minimum shipping fees in the event actual shipments are less than our allotted capacity. Future minimum throughput payments under these agreements at December 31, 2014 are as follows (in thousands):

Year Ending March 31,
2015 (three months)	$	23,199
2016	89,365
2017	53,750
2018	53,831
2019	53,037
Thereafter	109,272
Total	$	382,454

Construction Commitment

As discussed in Note 4, Grand Mesa completed a successful open season in which it received the requisite support, in the form of ship-or-pay volume commitments from multiple shippers, to begin construction of a 20-inch pipeline system. The estimated construction cost of Grand Mesa is $655.0 million and we anticipate that the pipeline will commence service in late 2016.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Sales and Purchase Contracts

We have entered into sales and purchase contracts for products to be delivered in future periods for which we expect the parties to physically settle the contracts with inventory. At December 31, 2014, we had the following such commitments outstanding:

	Volume	Value
	(in thousands)
Purchase commitments:
Natural gas liquids fixed-price (gallons)	60,493	$	51,807
Natural gas liquids index-price (gallons)	312,125	176,492
Crude oil index-price (barrels)	4,796	221,205
Sale commitments:
Natural gas liquids fixed-price (gallons)	221,370	236,371
Natural gas liquids index-price (gallons)	190,516	152,553
Crude oil index-price (barrels)	4,615	253,295

We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs. Contracts in the table above may have offsetting derivative contracts (described in Note 11) or inventory positions (described in Note 2).

Certain other forward purchase and sale contracts do not qualify for the normal purchase and normal sale election. These contracts are recorded at fair value on our condensed consolidated balance sheet and are not included in the table above. These contracts are included in the derivative disclosures in Note 11, and represent $83.0 million of our prepaid expenses and other current assets and $47.2 million of our accrued expenses and other payables at December 31, 2014.

Note 10 — Equity

Partnership Equity

The Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest, which consists of common units. Prior to August 2014, the Partnership’s limited partner interest also included subordinated units. The subordination period ended in August 2014, at which time all remaining subordinated units were converted into common units on a one-for-one basis.

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

Equity Issuance

On June 23, 2014, we completed a public offering of 8,000,000 common units. We received net proceeds of $338.0 million, after underwriting discounts and commissions of $12.3 million and offering costs of $0.5 million. During July 2014, the underwriters exercised their option to purchase an additional 767,100 units, from which we received net proceeds of $32.4 million.

Our Distribution Policy

Our general partner has adopted a cash distribution policy that requires us to pay a quarterly distribution to unitholders as of the record date to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner and its affiliates, referred to as “available cash.” The general partner will also receive, in addition to distributions on its 0.1% general partner interest, additional distributions based on the level of distributions to the limited partners. These distributions are referred to as “incentive distributions.” Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest In Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1% general partner interest, and assume that our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and has not transferred its incentive distribution rights.

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

During the three months ended December 31, 2014, we distributed a total of $65.0 million ($0.6088 per common and general partner notional unit) to our unitholders of record on November 4, 2014, which included an incentive distribution of $11.1 million to the general partner. In January 2015, we declared a distribution of $0.6175 per common unit, to be paid on February 13, 2015 to unitholders of record on February 6, 2015. This distribution is expected to be $66.5 million in total, including amounts to be paid on common and general partner notional units and the amount to be paid on incentive distribution rights.

TLP’s Distribution Policy

TLP’s partnership agreement requires it to pay a quarterly distribution to unitholders as of the record date to the extent TLP has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to TLP’s general partner and its affiliates, referred to as “available cash.” TLP’s general partner will also receive, in addition to distributions on its 2.0% general partner interest, additional distributions based on the level of distributions to the limited partners. These distributions are referred to as “incentive distributions.” TLP’s general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in TLP’s partnership agreement.

The following table illustrates the percentage allocations of available cash from operating surplus between TLP’s unitholders and TLP’s general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest In Distributions” are the percentage interests of TLP’s general partner and TLP’s unitholders in any available cash from operating surplus TLP distributes up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit,” until available cash from operating surplus TLP distributes reaches the next target distribution level, if any. The percentage interests shown for TLP’s unitholders and TLP’s general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for TLP’s general partner include its 2.0% general partner interest, and assume that TLP’s general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest and has not transferred its incentive distribution rights.

							Marginal Percentage Interest In
	Total Quarterly						Distributions
	Distribution Per Unit						Unitholders		General Partner
Minimum quarterly distribution					$	0.40	98	%	2	%
First target distribution	above	$	0.40	up to	$	0.44	98	%	2	%
Second target distribution	above	$	0.44	up to	$	0.50	85	%	15	%
Third target distribution	above	$	0.50	up to	$	0.60	75	%	25	%
Thereafter	above	$	0.60				50	%	50	%

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

During the three months ended December 31, 2014, TLP declared and paid a distribution of $0.665 per unit. We received a total of $4.0 million from this distribution on our general partner interest, incentive distribution rights, and limited partner interest. The noncontrolling interest owners received a total of $8.7 million from this distribution.

In January 2015, TLP declared a distribution of $0.665 per unit, which was paid on February 6, 2015. We received a total of $4.0 million from this distribution on our general partner interest, incentive distribution rights, and limited partner interest. The noncontrolling interest owners received a total of $8.6 million from this distribution.

Equity-Based Incentive Compensation

Our general partner has adopted a long-term incentive plan (“LTIP”), which allows for the issuance of equity-based compensation. Our general partner has granted certain restricted units to employees and directors, which vests 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 accrue to or are paid on the restricted units during the vesting period.

The following table summarizes the restricted unit activity during the nine months ended December 31, 2014:

Unvested restricted units at March 31, 2014	1,311,100
Units granted	585,403
Units vested and issued	(438,009	)
Units withheld for employee taxes	(231,194	)
Units forfeited	(174,000	)
Unvested restricted units at December 31, 2014	1,053,300

The scheduled vesting of our unvested restricted units is summarized below:

Vesting Date		Number of Awards
January 15, 2015		20,000
July 1, 2015		338,300
January 15, 2016		20,000
July 1, 2016		330,500
January 15, 2017		20,000
July 1, 2017		207,000
January 15, 2018		20,000
July 1, 2018		57,500
January 15, 2019		20,000
July 15, 2019		20,000
Unvested restricted units at December 31, 2014		1,053,300

We record the expense for the first tranche of each award on a straight-line basis over the period beginning with the grant date of the awards and ending with the vesting date of the tranche. We record the expense for succeeding tranches over the period beginning with the vesting date of the previous tranche and ending with the vesting date of the tranche.

At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using the closing price of our common units on the New York Stock Exchange on the balance sheet date, adjusted to reflect the fact that the holders of the unvested units are not entitled to distributions during the vesting period. We estimate the impact of the lack of distribution rights during the vesting period using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth.

We recorded expense related to restricted unit awards of $1.6 million and $4.1 million during the three months ended December 31, 2014 and 2013, respectively, and $23.3 million and $14.4 million during the nine months ended December 31, 2014 and 2013, respectively. We estimate that the future expense we will record on the unvested awards at December 31, 2014 will be as

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

follows (in thousands), after taking into consideration an estimate of forfeitures of approximately 70,000 units. For purposes of this calculation, we used the closing price of our common units on December 31, 2014, which was $27.99.

Year Ending March 31,
2015 (three months)	$	2,696
2016	9,499
2017	6,468
2018	2,786
Thereafter	1,301
Total	$	22,750

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

Balance at March 31, 2014	$	10,012
Expense recorded	23,285
Value of units vested and issued	(18,763		)
Taxes paid on behalf of participants	(9,901		)
Balance at December 31, 2014	$	4,633

The weighted-average fair value of the awards at December 31, 2014 was $23.75 per common unit, which was calculated as the closing price of the common units on December 31, 2014, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth.

The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common units. The maximum number of units deliverable under the plan automatically increases to 10% of the issued and outstanding common units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount. Units withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, when 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, 2014, approximately 6.9 million common units remain available for issuance under the LTIP.

Note 11 — Fair Value of Financial Instruments

Our cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, and other current assets and liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values due to their short-term nature.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Commodity Derivatives

The following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported on the condensed consolidated balance sheet at December 31, 2014:

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	99,633		$	(6,409	)
Level 2 measurements	98,384			(58,594		)
	198,017			(65,003		)

Netting of counterparty contracts (1)	(2,352		)	2,352
Cash collateral provided (held)	(74,047		)	60
Commodity derivatives on condensed consolidated balance sheet	$	121,618		$	(62,591	)

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

The following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported on the condensed consolidated balance sheet at March 31, 2014:

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	4,990		$	(3,258	)
Level 2 measurements	49,605			(43,303		)
	54,595			(46,561		)

Netting of counterparty contracts (1)	(4,347		)	4,347
Net cash collateral provided	456			—
Commodity derivatives on condensed consolidated balance sheet	$	50,704		$	(42,214	)

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

Our commodity derivative assets and liabilities are reported in the following accounts on the condensed consolidated balance sheets:

	December 31,			March 31,
	2014			2014
	(in thousands)
Prepaid expenses and other current assets	$	121,618		$	50,704
Accrued expenses and other payables	(62,591		)	(42,214		)
Net commodity derivative asset	$	59,027		$	8,490

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

The following table summarizes our open commodity derivative contract positions at December 31, 2014 and March 31, 2014. We do not account for these derivatives as hedges.

		Net Long (Short)		Fair Value
		Notional		of
		Positions		Net Assets
Contracts	Settlement Period	In Barrels		(Liabilities)
		(in thousands)

At December 31, 2014 -
Cross-commodity (1)	January 2015 – February 2015	288		$	(3,955	)
Crude oil fixed-price (2)	January 2015 – March 2015	(1,034	)	11,516
Crude oil index (3)	January 2015 – March 2015	1,291		2,853
Propane fixed-price (4)	January 2015 – March 2015	262		(3,827		)
Refined products fixed-price (4)	January 2015 – December 2015	(3,174	)	114,092
Renewable products fixed-price (4)	January 2015 – December 2015	(343	)	5,235
Other	January 2015 – January 2015	1,475		7,100
				133,014
Net cash collateral held				(73,987		)
Net commodity derivatives on condensed consolidated balance sheet				$	59,027

At March 31, 2014 -
Cross-commodity (1)	April 2014 – March 2015	140		$	(1,876	)
Crude oil fixed-price (2)	April 2014 – March 2015	(1,600	)	(2,796		)
Crude oil index (3)	April 2014 – December 2015	3,598		6,099
Propane fixed-price (4)	April 2014 – March 2015	60		1,753
Refined products fixed-price (4)	April 2014 – July 2014	732		560
Renewable products fixed-price (4)	April 2014 – July 2014	106		4,084
Other	April 2014	—		210
				8,034
Net cash collateral provided				456
Net commodity derivatives on condensed consolidated balance sheet				$	8,490

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

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

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

(4) Commodity fixed-price — We may have fixed price physical obligations, including inventory, offset by floating price physical sales or have floating price physical purchases offset by fixed price physical sales. The contracts listed in the this table as “fixed-price” represent derivatives we have entered into as an economic hedge against the risk of mismatches between fixed and floating price physical obligations.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

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

Three Months Ended					Nine Months Ended
December 31,					December 31,
2014		2013			2014		2013
(in thousands)
$	202,496	$	(8,830	)	$	240,992	$	(26,711	)

Credit Risk

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

We may enter into industry standard master netting agreements and may enter into cash collateral agreements requiring the counterparty to deposit funds into a brokerage margin account. The netting agreements reduce our credit risk by providing for net settlement of any offsetting positive and negative exposures with counterparties. The cash collateral agreements reduce the level of our net counterparty credit risk because the amount of collateral represents additional funds that we may access to net settle positions due us, and the amount of collateral adjusts each day in response to changes in the market value of counterparty derivatives.

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

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

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

Interest Rate Risk

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At December 31, 2014, we had $1.4 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 2.17%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.7 million, based on borrowings outstanding at December 31, 2014.

The TLP Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At December 31, 2014, TLP had $252.0 million of outstanding borrowings under the TLP Credit Facility at a rate of 2.66%. A change in interest rates of 0.125% would result in an increase or decrease in TLP’s annual interest expense of $0.3 million, based on borrowings outstanding at December 31, 2014.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Fair Value of Notes

The following table provides estimates of the fair values of our fixed-rate notes at December 31, 2014 (in thousands):

5.125% Notes due 2019	$	388,000
6.875% Notes due 2021	438,000
6.650% Notes due 2022	253,000

For the 2019 Notes and the 2021 Notes, the fair value estimates were developed by reference to broker quotes. These estimates would be classified as Level 2 in the fair value hierarchy.

For the 2022 Notes, the estimate was developed using observed yields on publicly-traded notes issued by other entities, adjusted for differences in the key terms of those notes and the key terms of our notes (examples include differences in the tenor of the debt, credit standing of the issuer, whether the notes are publicly-traded, and whether the notes are secured or unsecured). This estimate of fair value would be classified as Level 3 in the fair value hierarchy.

Note 12 — Segments

Certain financial data related to our segments is shown below. Transactions between segments are recorded based on prices negotiated between the segments.

Our liquids and retail propane segments each consist of two divisions, which are organized based on the location of the operations. Our refined products and renewables segment began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne.

Items labeled “corporate and other” in the table below include the operations of a compressor leasing business that we sold in February 2014 and certain natural gas marketing operations that we acquired in our December 2013 acquisition of Gavilon Energy and wound down during fiscal year 2014. The “corporate and other” category also includes certain corporate expenses that are incurred and are not allocated to the reportable segments. This data is included to reconcile the data for the reportable segments to data in our condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2014			2013			2014			2013
	(in thousands)
Revenues:
Crude oil logistics -
Crude oil sales	$	1,683,989		$	1,319,290		$	5,719,050		$	3,260,885
Crude oil transportation and other	17,260			6,198			42,456			25,927
Water solutions -
Service fees	30,870			15,589			72,809			42,864
Recovered hydrocarbons	19,355			20,693			66,704			40,929
Water transportation	16			5,490			10,761			12,682
Liquids -
Propane sales	395,456			518,541			858,335			833,815
Other product sales	329,814			336,654			924,798			895,113
Other revenues	9,595			7,695			22,125			25,809
Retail propane -
Propane sales	99,859			112,570			200,437			199,912
Distillate sales	29,102			37,648			59,327			66,079
Other revenues	10,804			11,377			26,261			27,275
Refined products and renewables -
Refined products sales	1,833,090			252,154			5,285,824			252,154
Renewables sales	126,212			54,446			374,911			54,446
Service fees	24,746			—			48,030			—
Corporate and other	(1,281		)	116,559			1,513			119,518
Elimination of intersegment sales	(56,741		)	(71,459		)	(132,055		)	(134,069		)
Total revenues	$	4,552,146		$	2,743,445		$	13,581,286		$	5,723,339

Depreciation and Amortization:
Crude oil logistics	$	10,630		$	5,827		$	29,601		$	13,841
Water solutions	17,807			18,258			52,472			37,052
Liquids	2,838			2,759			9,423			8,135
Retail propane	7,949			7,344			23,204			21,455
Refined products and renewables	9,788			331			22,549			331
Corporate and other	1,323			975			2,560			2,465
Total depreciation and amortization	$	50,335		$	35,494		$	139,809		$	83,279

Operating Income (Loss):
Crude oil logistics	$	(26,814	)	$	(6,424	)	$	(25,313	)	$	6,069
Water solutions	34,505			982			48,390			6,938
Liquids	(14,048		)	40,601			(4,032		)	53,091
Retail propane	21,477			21,696			16,829			15,672
Refined products and renewables	28,958			(1,005		)	36,525			(1,005		)
Corporate and other	(25,999		)	(14,681		)	(67,105		)	(36,993		)
Total operating income	$	18,079		$	41,169		$	5,294		$	43,772

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

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

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2014		2013		2014		2013
	(in thousands)
Additions to property, plant and equipment:
Crude oil logistics	$	16,517	$	153,209	$	97,930	$	188,671
Water solutions	69,137		11,533		117,209		81,715
Liquids	1,096		21,267		4,166		49,583
Retail propane	12,097		8,915		24,508		20,407
Refined products and renewables	21,330		—		533,611		—
Corporate and other	616		271		3,878		1,117
Total	$	120,793	$	195,195	$	781,302	$	341,493

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

	December 31,		March 31,
	2014		2014
	(in thousands)
Total assets:
Crude oil logistics	$	2,889,145	$	1,723,812
Water solutions	1,111,912		875,714
Liquids	629,973		577,795
Retail propane	523,564		541,832
Refined products and renewables	1,631,799		303,230
Corporate and other	119,509		144,840
Total	$	6,905,902	$	4,167,223

Long-lived assets, net:
Crude oil logistics	$	1,311,817	$	980,978
Water solutions	1,039,909		848,479
Liquids	210,383		274,846
Retail propane	441,992		438,324
Refined products and renewables	819,169		60,720
Corporate and other	52,292		47,961
Total	$	3,875,562	$	2,651,308

Note 13 — Transactions with Affiliates

SemGroup Corporation (“SemGroup”) holds ownership interests in us and in our general partner. We sell product to and purchase product from SemGroup, and these transactions are included within revenues and cost of sales in our condensed consolidated statements of operations. We also lease crude oil storage from SemGroup.

We purchase ethanol from one of our equity method investees. These transactions are reported within cost of sales in our condensed consolidated statements of operations.

Certain members of our management own interests in entities from which we have purchased products and services and to which we have sold products and services. The majority of our transactions with such entities represented crude oil purchases and sales and are reported within revenues or cost of sales in our condensed consolidated statements of operations, although $15.7 million of these transactions during the nine

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

months ended December 31, 2014 represented capital expenditures and were recorded as increases to property, plant and equipment.

The above transactions are summarized in the following table:

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2014		2013		2014		2013
	(in thousands)
Sales to SemGroup	$	64,470	$	50,742	$	181,703	$	54,522
Purchases from SemGroup	71,554		73,731		190,551		121,647
Sales to equity method investees	2,382		—		11,512		—
Purchases from equity method investees	44,580		—		115,546		—
Sales to entities affiliated with management	186		344		2,040		110,216
Purchases from entities affiliated with management	10,446		46,918		17,430		103,264

Receivables from affiliates consist of the following:

	December 31,		March 31,
	2014		2014
	(in thousands)
Receivables from SemGroup	$	41,993	$	7,303
Receivables from equity method investees	501		—
Receivables from entities affiliated with management	55		142
Total	$	42,549	$	7,445

Payables to affiliates consist of the following:

	December 31,		March 31,
	2014		2014
	(in thousands)
Payables to SemGroup	$	5,000	$	27,738
Payables to equity method investees	7,597		48,454
Payables to entities affiliated with management	169		654
Total	$	12,766	$	76,846

Note 14 — Condensed Consolidating Guarantor and Non-Guarantor Financial Information

Certain of our wholly-owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the 2019 Notes and the 2021 Notes (described in Note 7). Pursuant to Rule 3-10 of Regulation S-X, we have presented in columnar format the condensed consolidating financial information for NGL Energy Partners LP, NGL Energy Finance Corp. (which, along with NGL Energy Partners LP, is a co-issuer of the 2019 Notes and 2021 Notes), the guarantor subsidiaries on a combined basis, and the non-guarantor subsidiaries on a combined basis in the tables below.

During the periods presented in the tables below, the status of certain subsidiaries changed, in that they either became guarantors of or ceased to be guarantors of the 2019 Notes and 2021 Notes. Such changes have been given retrospective application in the tables below.

There are no significant restrictions upon the ability of the parent or any of the guarantor subsidiaries to obtain funds from their respective subsidiaries by dividend or loan, other than restrictions contained in TLP’s Credit Facility. None of the assets of the guarantor subsidiaries (other than the investments in non-guarantor subsidiaries) represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

For purposes of the tables below, (i) the condensed consolidating financial information is presented on a legal entity basis, (ii) investments in consolidated subsidiaries are accounted for as equity method investments, and (iii) contributions, distributions, and advances to or from consolidated entities are reported on a net basis within net changes in advances with consolidated entities in the condensed consolidating cash flow tables below.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

NGL ENERGY PARTNERS LP

Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)

	December 31, 2014
	NGL Energy
	Partners LP		NGL Energy			Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)		Finance Corp.			Subsidiaries			Subsidiaries			Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,287	$	—		$	23,573		$	3,696		$	—		$	30,556
Accounts receivable - trade, net of allowance for doubtful accounts	—		—			1,633,491			30,548			—			1,664,039
Accounts receivable - affiliates	—		—			42,141			408			—			42,549
Inventories	—		—			533,700			2,228			—			535,928
Prepaid expenses and other current assets	—		—			182,996			1,679			—			184,675
Total current assets	3,287		—			2,415,901			38,559			—			2,457,747

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—			962,264			510,031			—			1,472,295
GOODWILL	—		—			1,209,580			40,659			—			1,250,239
INTANGIBLE ASSETS, net of accumulated amortization	1,358		17,205			1,130,102			4,363			—			1,153,028
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—			217,750			260,694			—			478,444
NET INTERCOMPANY RECEIVABLES (PAYABLES)	417,570		846,754			(1,224,701		)	(39,623		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,498,365		—			(34,828		)	—			(1,463,537		)	—
OTHER NONCURRENT ASSETS	—		—			92,283			1,866			—			94,149
Total assets	$	1,920,580	$	863,959		$	4,768,351		$	816,549		$	(1,463,537	)	$	6,905,902

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable - trade	$	—	$	—		$	1,520,743		$	13,825		$	—		$	1,534,568
Accounts payable - affiliates	—		—			12,626			140			—			12,766
Accrued expenses and other payables	554		16,649			249,521			10,580			—			277,304
Advance payments received from customers	—		—			71,570			505			—			72,075
Current maturities of long-term debt	—		—			4,396			59			—			4,455
Total current liabilities	554		16,649			1,858,856			25,109			—			1,901,168

LONG-TERM DEBT, net of current maturities	250,000		850,000			1,401,125			252,197			—			2,753,322
OTHER NONCURRENT LIABILITIES	—		—			7,315			4,496			—			11,811

EQUITY
Partners’ equity (deficit)	1,670,026		(2,690		)	1,501,056			534,835			(2,033,112		)	1,670,115
Accumulated other comprehensive loss	—		—			(1		)	(88		)	—			(89		)
Noncontrolling interests	—		—			—			—			569,575			569,575
Total equity (deficit)	1,670,026		(2,690		)	1,501,055			534,747			(1,463,537		)	2,239,601
Total liabilities and equity	$	1,920,580	$	863,959		$	4,768,351		$	816,549		$	(1,463,537	)	$	6,905,902

(1) The parent is a co-issuer of the 2019 Notes and 2021 Notes that are included in the NGL Energy Finance Corp. column.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

NGL ENERGY PARTNERS LP

Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)

	March 31, 2014
	NGL Energy
	Partners LP		NGL Energy			Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)		Finance Corp.			Subsidiaries			Subsidiaries			Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,181	$	—		$	8,728		$	531		$	—		$	10,440
Accounts receivable - trade, net of allowance for doubtful accounts	—		—			887,789			13,115			—			900,904
Accounts receivable - affiliates	—		—			7,445			—			—			7,445
Inventories	—		—			306,434			3,726			—			310,160
Prepaid expenses and other current assets	—		—			80,294			56			—			80,350
Total current assets	1,181		—			1,290,690			17,428			—			1,309,299

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—			764,014			65,332			—			829,346
GOODWILL	—		—			1,105,008			1,998			—			1,107,006
INTANGIBLE ASSETS, net of accumulated amortization	1,169		11,552			700,603			1,632			—			714,956
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—			189,821			—			—			189,821
NET INTERCOMPANY RECEIVABLES (PAYABLES)	327,281		437,714			(720,737		)	(44,258		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,447,502		—			17,673			—			(1,465,175		)	—
OTHER NONCURRENT ASSETS	—		—			16,674			121			—			16,795
Total assets	$	1,777,133	$	449,266		$	3,363,746		$	42,253		$	(1,465,175	)	$	4,167,223

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable - trade	$	—	$	—		$	726,252		$	13,959		$	—		$	740,211
Accounts payable - affiliates	—		—			73,703			3,143			—			76,846
Accrued expenses and other payables	554		14,266			124,923			1,947			—			141,690
Advance payments received from customers	—		—			29,891			74			—			29,965
Current maturities of long-term debt	—		—			7,058			22			—			7,080
Total current liabilities	554		14,266			961,827			19,145			—			995,792

LONG-TERM DEBT, net of current maturities	250,000		450,000			929,754			80			—			1,629,834
OTHER NONCURRENT LIABILITIES	—		—			9,663			81			—			9,744

EQUITY
Partners’ equity (deficit)	1,526,579		(15,000		)	1,462,691			22,994			(1,470,449		)	1,526,815
Accumulated other comprehensive loss	—		—			(189		)	(47		)	—			(236		)
Noncontrolling interests	—		—			—			—			5,274			5,274
Total equity (deficit)	1,526,579		(15,000		)	1,462,502			22,947			(1,465,175		)	1,531,853
Total liabilities and equity	$	1,777,133	$	449,266		$	3,363,746		$	42,253		$	(1,465,175	)	$	4,167,223

(1) The parent is a co-issuer of the 2021 Notes that are included in the NGL Energy Finance Corp. column.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

NGL ENERGY PARTNERS LP

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	Three Months Ended December 31, 2014
	NGL Energy
	Partners LP			NGL Energy			Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp.			Subsidiaries			Subsidiaries			Adjustments			Consolidated
REVENUES	$	—		$	—		$	4,519,060		$	58,058		$	(24,972	)	$	4,552,146

COST OF SALES	—			—			4,322,892			13,748			(24,972		)	4,311,668

OPERATING COSTS AND EXPENSES:
Operating	—			—			76,599			21,162			—			97,761
Loss on disposal of assets, net	—			—			179			29,894			—			30,073
General and administrative	—			—			38,233			5,997			—			44,230
Depreciation and amortization	—			—			43,064			7,271			—			50,335

Operating Income (Loss)	—			—			38,093			(20,014		)	—			18,079

OTHER INCOME (EXPENSE):
Earnings of unconsolidated entities	—			—			4			1,238			—			1,242
Interest expense	(4,156		)	(13,911		)	(10,108		)	(1,887		)	11			(30,051		)
Other income, net	—			—			3,314			68			(11		)	3,371

Income (Loss) Before Income Taxes	(4,156		)	(13,911		)	31,303			(20,595		)	—			(7,359		)

INCOME TAX (PROVISION) BENEFIT	—			—			2,117			(27		)	—			2,090

EQUITY IN NET LOSS OF CONSOLIDATED SUBSIDIARIES	(6,762		)	—			(26,271		)	—			33,033			—

Net Income (Loss)	(10,918		)	(13,911		)	7,149			(20,622		)	33,033			(5,269		)

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER													(11,783		)	(11,783		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS													(5,649		)	(5,649		)

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	(10,918	)	$	(13,911	)	$	7,149		$	(20,622	)	$	15,601		$	(22,701	)

(1) The parent is a co-issuer of the 2019 Notes and 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

NGL ENERGY PARTNERS LP

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	Three Months Ended December 31, 2013
	NGL Energy
	Partners LP			NGL Energy			Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp			Subsidiaries			Subsidiaries			Adjustments			Consolidated

REVENUES	$	—		$	—		$	2,705,219		$	38,361		$	(135	)	$	2,743,445

COST OF SALES	—			—			2,542,290			33,874			(135		)	2,576,029

OPERATING COSTS AND EXPENSES:
Operating	—			—			66,423			2,498			—			68,921
Loss on disposal of assets, net	—			—			340			—			—			340
General and administrative	—			—			21,258			234			—			21,492
Depreciation and amortization	—			—			34,660			834			—			35,494

Operating Income	—			—			40,248			921			—			41,169

OTHER INCOME (EXPENSE):
Interest expense	(4,254		)	(6,862		)	(5,628		)	(12		)	11			(16,745		)
Other income, net	—			—			149			16			(11		)	154

Income (Loss) Before Income Taxes	(4,254		)	(6,862		)	34,769			925			—			24,578

INCOME TAX PROVISION	—			—			(526		)	—			—			(526		)

EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES	28,152			—			771			—			(28,923		)	—

Net Income (Loss)	23,898			(6,862		)	35,014			925			(28,923		)	24,052

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER													(4,260		)	(4,260		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS													(154		)	(154		)

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	23,898		$	(6,862	)	$	35,014		$	925		$	(33,337	)	$	19,638

(1) The parent is a co-issuer of the 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

NGL ENERGY PARTNERS LP

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	Nine Months Ended December 31, 2014
	NGL Energy
	Partners LP			NGL Energy			Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

REVENUES	$	—		$	—		$	13,471,832		$	134,479		$	(25,025	)	$	13,581,286

COST OF SALES	—			—			12,999,773			50,438			(25,025		)	13,025,186

OPERATING COSTS AND EXPENSES:
Operating	—			—			222,744			39,872			—			262,616
Loss on disposal of assets, net	—			—			4,953			29,686			—			34,639
General and administrative	—			—			102,357			11,385			—			113,742
Depreciation and amortization	—			—			120,609			19,200			—			139,809

Operating Income (Loss)	—			—			21,396			(16,102		)	—			5,294

OTHER INCOME (EXPENSE):
Earnings of unconsolidated entities	—			—			4,879			2,625			—			7,504
Interest expense	(12,469		)	(35,191		)	(28,166		)	(3,404		)	34			(79,196		)
Other income, net	—			—			2,258			139			(34		)	2,363

Income (Loss) Before Income Taxes	(12,469		)	(35,191		)	367			(16,742		)	—			(64,035		)

INCOME TAX (PROVISION) BENEFIT	—			—			3,110			(133		)	—			2,977

EQUITY IN NET LOSS OF CONSOLIDATED SUBSIDIARIES	(57,648		)	—			(25,934		)	—			83,582			—

Net Loss	(70,117		)	(35,191		)	(22,457		)	(16,875		)	83,582			(61,058		)

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER													(32,220		)	(32,220		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS													(9,059		)	(9,059		)

NET LOSS ALLOCATED TO LIMITED PARTNERS	$	(70,117	)	$	(35,191	)	$	(22,457	)	$	(16,875	)	$	42,303		$	(102,337	)

(1) The parent is a co-issuer of the 2019 Notes and 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

NGL ENERGY PARTNERS LP

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

				Nine Months Ended December 31, 2013
	NGL Energy
	Partners LP			NGL Energy			Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

REVENUES	$	—		$	—		$	5,619,750		$	103,782		$	(193	)	$	5,723,339

COST OF SALES	—			—			5,278,180			89,968			(193		)	5,367,955

OPERATING COSTS AND EXPENSES:
Operating	—			—			164,028			7,544			—			171,572
Loss on disposal of assets, net	—			—			2,445			58			—			2,503
General and administrative	—			—			53,555			703			—			54,258
Depreciation and amortization	—			—			80,660			2,619			—			83,279

Operating Income	—			—			40,882			2,890			—			43,772

OTHER INCOME (EXPENSE):
Interest expense	(12,622		)	(6,862		)	(18,937		)	(40		)	34			(38,427		)
Other income (expense), net	—			—			776			(119		)	(34		)	623

Income (Loss) Before Income Taxes	(12,622		)	(6,862		)	22,721			2,731			—			5,968

INCOME TAX PROVISION	—			—			(356		)	—			—			(356		)

EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES	17,946			—			2,443			—			(20,389		)	—

Net Income (Loss)	5,324			(6,862		)	24,808			2,731			(20,389		)	5,612

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER													(8,399		)	(8,399		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS													(288		)	(288		)

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	5,324		$	(6,862	)	$	24,808		$	2,731		$	(29,076	)	$	(3,075	)

(1) The parent is a co-issuer of the 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

NGL ENERGY PARTNERS LP

Condensed Consolidating Statements of Comprehensive Income (Loss)

(U.S. Dollars in Thousands)

	Three Months Ended December 31, 2014
	NGL Energy
	Partners LP			NGL Energy			Guarantor		Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp.			Subsidiaries		Subsidiaries			Adjustments		Consolidated

Net income (loss)	$	(10,918	)	$	(13,911	)	$	7,149	$	(20,622	)	$	33,033	$	(5,269	)

Other comprehensive loss	—			—			—		(16		)	—		(16		)

Comprehensive income (loss)	$	(10,918	)	$	(13,911	)	$	7,149	$	(20,638	)	$	33,033	$	(5,285	)

(1) The parent is a co-issuer of the 2019 Notes and 2021 Notes.

	Three Months Ended December 31, 2013
	NGL Energy
	Partners LP		NGL Energy			Guarantor			Non-Guarantor			Consolidating
	(Parent) (2)		Finance Corp.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

Net income (loss)	$	23,898	$	(6,862	)	$	35,014		$	925		$	(28,923	)	$	24,052

Other comprehensive loss	—		—			(80		)	(20		)	—			(100		)

Comprehensive income (loss)	$	23,898	$	(6,862	)	$	34,934		$	905		$	(28,923	)	$	23,952

(2) The parent is a co-issuer of the 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

NGL ENERGY PARTNERS LP

Condensed Consolidating Statements of Comprehensive Income (Loss)

(U.S. Dollars in Thousands)

	Nine Months Ended December 31, 2014
	NGL Energy
	Partners LP			NGL Energy			Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp.			Subsidiaries			Subsidiaries			Adjustments		Consolidated

Net loss	$	(70,117	)	$	(35,191	)	$	(22,457	)	$	(16,875	)	$	83,582	$	(61,058	)

Other comprehensive income (loss)	—			—			189			(42		)	—		147

Comprehensive loss	$	(70,117	)	$	(35,191	)	$	(22,268	)	$	(16,917	)	$	83,582	$	(60,911	)

(1) The parent is a co-issuer of the 2019 Notes and 2021 Notes.

	Nine Months Ended December 31, 2013
	NGL Energy
	Partners LP		NGL Energy			Guarantor			Non-Guarantor			Consolidating
	(Parent) (2)		Finance Corp.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

Net income (loss)	$	5,324	$	(6,862	)	$	24,808		$	2,731		$	(20,389	)	$	5,612

Other comprehensive loss	—		—			(80		)	(50		)	—			(130		)

Comprehensive income (loss)	$	5,324	$	(6,862	)	$	24,728		$	2,681		$	(20,389	)	$	5,482

(2) The parent is a co-issuer of the 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

NGL ENERGY PARTNERS LP

Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)

	Nine Months Ended December 31, 2014
	NGL Energy
	Partners LP			NGL Energy			Guarantor			Non-Guarantor
	(Parent) (1)			Finance Corp.			Subsidiaries			Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(12,263	)	$	(30,851	)	$	86,074		$	38,880		$	81,840

INVESTING ACTIVITIES:
Purchases of long-lived assets	—			—			(130,522		)	(4,913		)	(135,435		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	—			—			(1,108,646		)	(5,399		)	(1,114,045		)
Cash flows from commodity derivatives	—			—			190,455			—			190,455
Proceeds from sales of assets	—			—			1,230			14,006			15,236
Investments in unconsolidated entities	—			—			(13,244		)	(20,284		)	(33,528		)
Distributions of capital from unconsolidated entities	—			—			3,396			5,340			8,736
Other investments	—			—			(45,855		)	—			(45,855		)
Other	—			—			—			(66		)	(66		)
Net cash used in investing activities	—			—			(1,103,186		)	(11,316		)	(1,114,502		)

FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	—			—			3,016,000			80,700			3,096,700
Payments on revolving credit facilities	—			—			(2,542,000		)	(62,700		)	(2,604,700		)
Issuance of notes	—			400,000			—			—			400,000
Payments on other long-term debt	—			—			(5,454		)	(22		)	(5,476		)
Debt issuance costs	(394		)	(7,609		)	(2,823		)	—			(10,826		)
Contributions	408			—			—			—			408
Distributions to partners	(176,051		)	—			—			—			(176,051		)
Distributions to noncontrolling interest owners	—			—			—			(17,497		)	(17,497		)
Proceeds from sale of common units, net of offering costs	370,376			—			—			—			370,376
Net changes in advances with consolidated entities	(179,970		)	(361,540		)	566,390			(24,880		)	—
Other	—			—			(156		)	—			(156		)
Net cash provided by (used in) financing activities	14,369			30,851			1,031,957			(24,399		)	1,052,778
Net increase in cash and cash equivalents	2,106			—			14,845			3,165			20,116
Cash and cash equivalents, beginning of period	1,181			—			8,728			531			10,440
Cash and cash equivalents, end of period	$	3,287		$	—		$	23,573		$	3,696		$	30,556

(1) The parent is a co-issuer of the 2019 Notes and 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

NGL ENERGY PARTNERS LP

Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)

	Nine Months Ended December 31, 2013
	NGL Energy
	Partners LP			NGL Energy			Guarantor			Non-Guarantor
	(Parent) (1)			Finance Corp.			Subsidiaries			Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(12,468	)	$	—		$	72,463		$	4,778		$	64,773

INVESTING ACTIVITIES:
Purchases of long-lived assets	—			—			(64,882		)	(43,063		)	(107,945		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	(334,084		)	—			(903,808		)	(2,283		)	(1,240,175		)
Cash flows from commodity derivatives	—			—			(30,659		)	—			(30,659		)
Proceeds from sales of assets	—			—			7,301			1			7,302
Investments in unconsolidated entities	—			—			(2,000		)	—			(2,000		)
Distributions of capital from unconsolidated entities	—			—			1,591			—			1,591
Other	—			—			(102		)	—			(102		)
Net cash used in investing activities	(334,084		)	—			(992,559		)	(45,345		)	(1,371,988		)

FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facility	—			—			2,040,500			—			2,040,500
Payments on revolving credit facility	—			—			(1,709,500		)	—			(1,709,500		)
Issuance of notes	—			450,000			—			—			450,000
Proceeds from borrowings on other long-term debt	—			—			780			100			880
Payments on other long-term debt	—			—			(6,697		)	(16		)	(6,713		)
Debt issuance costs	(646		)	(12,015		)	(11,400		)	—			(24,061		)
Contributions	736			—			—			2,000			2,736
Distributions to partners	(98,657		)	—			—			—			(98,657		)
Distributions to noncontrolling interest owners	—			—			—			(840		)	(840		)
Proceeds from sale of common units, net of offering costs	650,210			—			—			—			650,210
Net changes in advances with consolidated entities	(204,435		)	(437,985		)	603,218			39,202			—
Net cash provided by financing activities	347,208			—			916,901			40,446			1,304,555
Net increase (decrease) in cash and cash equivalents	656			—			(3,195		)	(121		)	(2,660		)
Cash and cash equivalents, beginning of period	—			—			11,206			355			11,561
Cash and cash equivalents, end of period	$	656		$	—		$	8,011		$	234		$	8,901

(1) The parent is a co-issuer of the 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2014 and March 31, 2014, and for the

Three Months and Nine Months Ended December 31, 2014 and 2013

Note 15 — Subsequent Events

Retail Propane Acquisition

During January 2015, we completed an acquisition of a retail propane business. We paid $25.0 million of cash and issued 132,100 common units, valued at $3.8 million, in exchange for these assets and operations.

Water Solutions Facility Acquisition

As described in Note 4, we are party to a development agreement that provides us a right to purchase water treatment and disposal facilities developed by the other party to the agreement. During January 2015, we purchased one water facility under this development agreement for $12.0 million of cash.

Natural Gas Liquids Storage Acquisition

In February 2015, we signed an agreement to acquire an entity that owns a natural gas liquids salt dome storage facility in Utah. The purchase price will be approximately $280.0 million, of which $80.0 million will be payable in cash and approximately $200.0 million will be payable in our common units.

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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, 2014. 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, 2014.

Overview

We are a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At December 31, 2014, our operations include:

· Our refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the 2.0% general partner interest and a 19.7% limited partner interest in TransMontaigne Partners L.P. (“TLP”), which conducts refined products terminaling operations. TLP also owns a 42.5% interest in Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and a 50% interest in Frontera Brownsville LLC, which are entities that own refined products storage facilities.

Crude Oil Logistics

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

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

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

	Spot Price Per Barrel
	Low		High		At Period End
Three Months Ended December 31,
2014	$	53.27	$	91.01	$	53.27
2013	92.30		104.10		98.42

Nine Months Ended December 31,
2014	$	53.27	$	107.26	$	53.27
2013	86.68		110.53		98.42

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 segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, from the sale of recycled water and recovered hydrocarbons, and from the disposal of tank bottoms and drilling mud. 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 the DJ Basin have committed to deliver to our facilities all wastewater produced at wells in a designated area. Most of the customers at our other facilities are not under volume commitments, although one customer has committed to deliver at least 50,000 barrels of wastewater per day to our facilities in Texas.

Liquids

Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the products to retailers, refiners, petrochemical plants, and other participants in the wholesale markets. Our liquids segment owns more than 20 terminals, operates a fleet of owned and leased railcars, and leases underground storage capacity. We attempt to reduce our exposure to the impact of price fluctuations by using back-to-back contracts and pre-sale agreements that allow us to lock in a margin on a percentage of our winter volumes. We also attempt to reduce our exposure to the impact of price fluctuations by entering into swap agreements whereby we agree to pay a floating rate and receive a fixed rate on a specified notional amount of product. We enter into these agreements as economic hedges against the potential decline in the value of a portion of our inventory.

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

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

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

	Conway, Kansas						Mt. Belvieu, Texas
	Spot Price Per Gallon						Spot Price Per Gallon
	Low		High		At Period End		Low		High		At Period End
Three Months Ended December 31,
2014	$	0.42	$	1.09	$	0.42	$	0.48	$	1.06	$	0.48
2013	1.04		1.46		1.46		1.07		1.32		1.26

Nine Months Ended December 31,
2014	$	0.42	$	1.13	$	0.42	$	0.48	$	1.13	$	0.48
2013	0.77		1.46		1.46		0.81		1.32		1.26

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

	Spot Price Per Gallon
	Low		High		At Period End
Three Months Ended December 31,
2014	$	0.66	$	1.24	$	0.66
2013	1.30		1.54		1.38

Nine Months Ended December 31,
2014	$	0.66	$	1.30	$	0.66
2013	1.08		1.54		1.38

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 is a “cost-plus” business that sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers. Our retail propane segment purchases the majority of its propane from our liquids segment. Our retail propane segment generates margins based on the difference between the wholesale cost of product and the selling price of the product in the retail markets. These margins fluctuate over time due to supply and demand conditions. Weather conditions can have a significant impact on our sales volumes and prices, as a large portion of our sales are to residential customers who purchase propane and distillates for home heating purposes.

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

The retail propane business is weather-sensitive and subject to seasonal volume variations due to propane’s primary use as a heating source in residential and commercial buildings and for agricultural purposes. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

Refined Products and Renewables

Our refined products and renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We conduct our operations in the United States along the Gulf Coast, in the Midwest, in Houston and Brownsville, Texas, along the Mississippi and Ohio rivers, and in the Southeast.

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The range of low and high spot gasoline prices per gallon using NYMEX gasoline prompt-month futures and the prices at period end were as follows:

	Spot Price Per Gallon
	Low		High		At Period End
Three Months Ended December 31, 2014	$	1.44	$	2.45	$	1.44

Nine Months Ended December 31, 2014	1.44		3.13		1.44

The range of low and high spot diesel prices per gallon using NYMEX ULSD prompt-month futures and the prices at period end were as follows:

	Spot Price Per Gallon
	Low		High		At Period End
Three Months Ended December 31, 2014	$	1.85	$	2.66	$	1.85

Nine Months Ended December 31, 2014	1.85		3.05		1.85

Recent Developments

Natural Gas Liquids Storage Acquisition

Crude Oil Rail Transloading Facility

On October 2, 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments, capable of handling unit trains west of Albuquerque, New Mexico in the San Juan Basin.

Grand Mesa Pipeline, LLC

In September 2014, we entered into a joint venture with RimRock Midstream, LLC (“RimRock”) whereby each party owned a 50% interest in Grand Mesa Pipeline, LLC (“Grand Mesa”). Grand Mesa is constructing a crude oil pipeline originating in Weld County, Colorado and terminating at our Cushing, Oklahoma terminal. In October 2014, Grand Mesa completed a successful open season in which it received the requisite support, in the form of ship-or-pay volume commitments from multiple shippers, to begin construction of a 20-inch pipeline system. In November 2014, we acquired RimRock’s 50% ownership interest in Grand Mesa for $310.0 million in cash and preliminarily allocated this to the throughput agreement intangible asset. We anticipate that the pipeline will commence service in late 2016, at which time we will begin to amortize this intangible asset.

Acquisitions

As described below, we completed numerous acquisitions during the year ended March 31, 2014 and the nine months ended December 31, 2014. These acquisitions impact the comparability of our results of operations between our current and prior fiscal years.

Bakken Water Solutions Facilities

On November 21, 2014, we completed the acquisition of two saltwater disposal facilities in the Bakken Basin in North Dakota for $34.6 million of cash.

TransMontaigne Inc.

On July 1, 2014, we acquired TransMontaigne Inc. (“TransMontaigne”) for $200.3 million of cash, net of cash acquired (including $174.1 million paid at closing and $26.2 million paid upon completion of the working capital settlement). As part of this transaction, we also purchased $380.4 million of inventory from the previous owner of TransMontaigne (including $346.9 million paid at closing and $33.5 million subsequently paid as the working capital settlement process progressed). The operations of TransMontaigne include the marketing of refined products and crude oil. As part of this transaction, we acquired the 2.0% general partner interest, the incentive distribution rights, and a 19.7% limited partner interest in TLP, and assumed certain terminaling service agreements with TLP from an affiliate of the previous owner of TransMontaigne.

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Water Solutions Facilities

As described below under “High Roller Wells Big Lake SWD No. 1 Ltd.”, we are party to a development agreement that provides us a right to purchase water treatment and disposal facilities developed by the other party to the agreement. During the nine months ended December 31, 2014, we purchased 11 water treatment and disposal facilities under this development agreement. We also purchased a 75% interest in one additional water treatment and disposal facility in July 2014 from a different seller. On a combined basis, we paid $161.0 million of cash for these 12 facilities.

During January 2015, we purchased one water facility under this development agreement for $12.0 million of cash.

Water Supply Company

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

Gavilon, LLC

In December 2013, we acquired the ownership interests of Gavilon, LLC (“Gavilon Energy”). The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas and Louisiana, a 50% interest in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma, and an interest in an ethanol production facility in the Midwest. The operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids, and also include crude oil storage in Cushing, Oklahoma.

Coastal Plains Disposal #1, LLC (“Coastal”)

In September 2013, we acquired the ownership interests in three water treatment and disposal facilities in the Eagle Ford Basin in Texas, and an option to acquire an additional facility which we exercised in March 2014.

Oilfield Water Lines LP (“OWL”)

In August 2013, we acquired the ownership interests in four water treatment and disposal facilities located in the Eagle Ford Basin in Texas.

High Roller Wells Big Lake SWD No. 1 Ltd. (“Big Lake”)

In July 2013, we acquired a water treatment and disposal facility located in the Permian Basin in Texas. As part of this transaction, we entered into a five-year development agreement that provides us a right to purchase water treatment and disposal facilities that may be developed by the other party to the agreement.

Crescent Terminals, LLC and Cierra Marine, LP

In July 2013, we acquired the operating assets of Crescent Terminals, LLC (“Crescent”), which operates a leased crude oil storage and dock facility in Port Aransas, Texas. In addition, we also purchased the ownership interests of Cierra Marine, LP (“Cierra Marine”), whereby we acquired a fleet of four towboats and seven crude oil barges operating in the intercoastal waterways of Texas.

Summary Discussion of Operating Results for the Three Months Ended December 31, 2014

During the three months ended December 31, 2014, we generated operating income of $18.1 million, compared to operating income of $41.2 million during the three months ended December 31, 2013.

Our crude oil logistics segment generated an operating loss of $26.8 million during the three months ended December 31, 2014, compared to an operating loss of $6.4 million during the three months ended December 31, 2013. Crude oil prices declined sharply during the three months ended December 31, 2014, which adversely impacted our margins, due to the difference in timing of when we purchase product and when we deliver it to the point of sale. In addition, we recorded a lower of cost or market adjustment of $20.0 million at December 31, 2014.

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Our water solutions segment generated operating income of $34.5 million during the three months ended December 31, 2014, compared to operating income of $1.0 million during the three months ended December 31, 2013. This increase was due in part to an increase in the volume of wastewater processed, which was due to increased demand at existing facilities and to the development and acquisition of new facilities. We have historically entered into derivatives to protect against the risk of a decline in the price of crude oil we expect to recover in the process of treating the wastewater. During the three months ended December 31, 2014 and 2013, cost of sales was reduced by $29.1 million and $0.5 million, respectively, of net gains on derivatives. During the three months ended December 31, 2014, we settled certain derivative contracts that related to crude oil we expect to recover in the months from April 2015 to September 2015; as of December 31, 2014, we had open derivative contracts related to a portion of the crude oil we expect to recover in the months from January 2015 to March 2015.

Our liquids segment generated an operating loss of $14.0 million during the three months ended December 31, 2014, compared to operating income of $40.6 million during the three months ended December 31, 2013. During the three months ended December 31, 2014, we recorded a loss of $29.9 million on the sale of a natural gas liquids terminal. Propane margins per gallon were lower during the three months ended December 31, 2014 than during the three months ended December 31, 2013, as a result of declining product prices. We use a weighted-average inventory costing method for our wholesale propane inventory, with the costing pools segregated based on the location of the inventory. During periods of declining prices, such as we experienced during the three months ended December 31, 2014, our margins are typically reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher. One of our business strategies is to purchase and store inventory during the warmer months for sale during the winter months. We seek to lock in a margin on inventory held in storage through back-to-back purchases and sales, fixed-price forward sale commitments, and financial derivatives. We also have contracts whereby we have committed to purchase ratable volumes each month at index prices. We seek to manage the price risk associated with these contracts primarily by selling the inventory immediately after it is received. When we sell product, we record the cost of the sale at the average cost of all inventory at that location, which may include inventory stored for sale in the future. During periods of rising prices, this can result in greater margins on these sales. During periods of falling prices, this can result in lower margins on these sales. We would generally expect the impact of these two different strategies being in the same inventory costing pools to even out over the course of a full fiscal year.

Our retail propane segment generated operating income of $21.5 million during the three months ended December 31, 2014, compared to operating income of $21.7 million during the three months ended December 31, 2013. Although sales volumes were lower during the three months ended December 31, 2014 than during the three months ended December 31, 2013, due to warmer weather conditions, product margins per gallon were higher.

Our refined products and renewables segment generated operating income of $29.0 million during the three months ended December 31, 2014, compared to an operating loss of $1.0 million during the three months ended December 31, 2013. Our refined products and renewables segment began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne.

We recorded $1.2 million of earnings from our equity method investments during the three months ended December 31, 2014. Most of our equity method investments were acquired in our December 2013 acquisition of Gavilon Energy and our July 2014 acquisition of TransMontaigne.

We incurred interest expense of $30.1 million during the three months ended December 31, 2014, compared to interest expense of $16.7 million during the three months ended December 31, 2013. The increase was due primarily to borrowings to finance acquisitions.

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Consolidated Results of Operations

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

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2014			2013			2014			2013
	(in thousands)
Total revenues	$	4,552,146		$	2,743,445		$	13,581,286		$	5,723,339
Total cost of sales	4,311,668			2,576,029			13,025,186			5,367,955
Operating and general and administrative expenses	172,064			90,753			410,997			228,333
Depreciation and amortization	50,335			35,494			139,809			83,279
Operating income	18,079			41,169			5,294			43,772
Earnings of unconsolidated entities	1,242			—			7,504			—
Interest expense	(30,051		)	(16,745		)	(79,196		)	(38,427		)
Other income, net	3,371			154			2,363			623
Income (loss) before income taxes	(7,359		)	24,578			(64,035		)	5,968
Income tax (provision) benefit	2,090			(526		)	2,977			(356		)
Net income (loss)	(5,269		)	24,052			(61,058		)	5,612
Less: Net income allocated to general partner	(11,783		)	(4,260		)	(32,220		)	(8,399		)
Less: Net income attributable to noncontrolling interests	(5,649		)	(154		)	(9,059		)	(288		)
Net income (loss) allocated to limited partners	$	(22,701	)	$	19,638		$	(102,337	)	$	(3,075	)

See the detailed discussion of revenues, cost of sales, operating expenses, general and administrative expenses, depreciation and amortization expense and operating income by segment below. The acquisitions described above had a significant impact on the comparability of our results of operations during the three months and nine months ended December 31, 2014 and 2013.

Non-GAAP Financial Measures

The following table reconciles net income (loss) 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,
	2014			2013			2014			2013
	(in thousands)
Net income (loss) attributable to parent equity	$	(10,918	)	$	23,898		$	(70,117	)	$	5,324
Income tax provision (benefit)	(2,099		)	526			(2,997		)	356
Interest expense	28,892			16,745			77,338			38,427
Depreciation and amortization	51,065			36,251			143,781			85,199
EBITDA	66,940			77,420			148,005			129,306
Net unrealized (gains) losses on derivatives	(4,724		)	(1,954		)	(13,414		)	1,791
Lower of cost or market adjustments	29,399			—			32,236			—
Loss on disposal of assets, net	30,072			340			34,680			2,503
Equity-based compensation expense (1)	14,870			4,078			36,529			14,370
Adjusted EBITDA	$	136,557		$	79,884		$	238,036		$	147,970

(1) During January 2015, we reached an agreement with certain employees whereby certain bonus commitments otherwise payable in cash subsequent to our fiscal year end would instead be paid using our common units. The amounts in the table above include the compensation expense during the nine months ended December 31, 2014 associated with these bonuses.

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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 unrealized gains or losses on derivatives, lower of cost or market adjustments, gains or losses on the disposal or impairment of assets, and equity-based compensation expense. EBITDA and Adjusted EBITDA should not be considered alternatives 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 to investors for evaluating our ability to make quarterly distributions to our unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information to investors 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 make a distinction between unrealized gains/losses on derivatives and realized gains/losses on derivatives. During the period when a derivative contract is open, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously-recorded unrealized gain or loss and record a realized gain or loss. For the three months and nine months ended December 31, 2014, we excluded lower of cost or market adjustments to inventory from the calculation of Adjusted EBITDA. A portion of these adjustments was hedged through financial derivatives, and the related unrealized gains were also excluded from the calculation of Adjusted EBITDA.

We acquired TransMontaigne in July 2014. We are still in the process of developing procedures to calculate realized and unrealized gains and losses for these operations in the same way we calculate them for our other operations. Accordingly, the net unrealized gains and losses in the table above exclude any unrealized gains and losses related to TransMontaigne. As of December 31, 2014, the refined products business acquired in the TransMontaigne business combination held futures contracts to protect against declines in the value of refined products inventories. As a result of declining prices in December, we recorded a lower of cost or market adjustment to these inventories and recorded gains on the open futures contracts. The loss associated with the lower of cost or market adjustment and the gains associated with the futures contracts pertaining to the TransMontaigne business are included in Adjusted EBITDA in the table above.

A portion of the revenues of our water solutions business is generated from the sale of crude oil that we recover in the process of treating the wastewater. We have historically entered into derivative contracts to protect against the risk of declines in the value of the crude oil we expect to recover in future months. During the three months ended December 31, 2014, we settled certain derivative contracts that related to crude oil we expect to recover in the months from April 2015 to September 2015 and realized a gain of $17.9 million. Of this gain, $9.4 million was attributable to derivatives with scheduled settlement dates during the quarter ending June 30, 2015 and $8.5 million was attributable to derivative contracts with scheduled settlement dates during the quarter ending September 30, 2015. As of December 31, 2014, our water solutions business had open derivative contracts with settlement dates through March 2015.

During the three months ended December 31, 2014, we recorded $0.7 million of expense related to legal and advisory costs associated with acquisitions and $7.6 million of compensation expense associated with acquisitions (including certain bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon the successful completion of the sale of the business, and compensation expense related to termination benefits for certain TransMontaigne employees). During the nine months ended December 31, 2014, we recorded $5.0 million of expense related to legal and advisory costs associated with acquisitions and $15.3 million of compensation expense associated with acquisitions (including certain bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon the successful completion of the sale of the business, and compensation expense related to termination benefits for certain TransMontaigne employees).

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The following tables reconcile depreciation and amortization amounts per the EBITDA table above to depreciation and amortization amounts reported in our condensed consolidated statements of operations and condensed consolidated statements of cash flows:

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2014			2013			2014			2013
	(in thousands)
Reconciliation to condensed consolidated statements of operations:
Depreciation and amortization per EBITDA table	$	51,065		$	36,251		$	143,781		$	85,199
Intangible asset amortization recorded to cost of sales	(1,818		)	(943		)	(5,939		)	(2,517		)
Depreciation and amortization of unconsolidated entities	(5,485		)	—			(14,100		)	—
Depreciation and amortization attributable to noncontrolling interests	6,573			186			16,067			597
Depreciation and amortization per condensed consolidated statements of operations	$	50,335		$	35,494		$	139,809		$	83,279

	Nine Months Ended
	December 31,
	2014			2013
	(in thousands)
Reconciliation to condensed consolidated statements of cash flows:
Depreciation and amortization per EBITDA table	$	143,781		$	85,199
Amortization of debt issuance costs recorded to interest expense	6,480			4,055
Depreciation and amortization of unconsolidated entities	(14,100		)	—
Depreciation and amortization attributable to noncontrolling interests	16,067			597
Depreciation and amortization per condensed consolidated statements of cash flows	$	152,228		$	89,851

The following table summarizes maintenance and expansion capital expenditures (exclusive of acquisitions) for each of the periods indicated (in thousands):

	Expansion		Maintenance		Total
	Capital		Capital		Capital
	Expenditures		Expenditures		Expenditures

Three months ended December 31, 2014	$	41,284	$	11,300	$	52,584
Three months ended December 31, 2013	30,946		9,600		40,546

Nine months ended December 31, 2014	106,935		28,500		135,435
Nine months ended December 31, 2013	83,345		24,600		107,945

Segment Operating Results for the Three Months Ended December 31, 2014 and 2013

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We expanded our crude oil logistics business through a number of acquisitions, including our acquisition of Gavilon Energy in December 2013. We expanded our water solutions business through numerous acquisitions of water treatment and disposal facilities. Our refined products and renewables businesses began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne. The results of operations of our liquids and retail propane segments are impacted by seasonality, due primarily to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our sales volumes and revenues. For these and other reasons, our results of operations for the three months ended December 31, 2014 are not necessarily indicative of the results to be expected for future periods or for the full fiscal year ending March 31, 2015.

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Volumes

The following table summarizes the volume of product sold and water delivered during the three months ended December 31, 2014 and 2013. Volumes shown in the following table include intersegment sales.

	Three Months Ended
	December 31,
Segment	2014	2013	Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)	22,658	13,466	9,192

Water solutions
Water delivered (barrels)	38,853	18,255	20,598

Liquids
Propane sold (gallons)	380,528	410,286	(29,758	)
Other products sold (gallons)	230,312	207,473	22,839

Retail propane
Propane sold (gallons)	48,324	50,623	(2,299	)
Distillates sold (gallons)	9,381	10,442	(1,061	)

Refined products and renewables
Refined products sold (gallons)	838,000	89,063	748,937
Renewable products sold (gallons)	60,805	21,532	39,273

Operating Income (Loss) by Segment

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

	Three Months Ended
	December 31,
Segment	2014			2013			Change
	(in thousands)
Crude oil logistics	$	(26,814	)	$	(6,424	)	$	(20,390	)
Water solutions	34,505			982			33,523
Liquids	(14,048		)	40,601			(54,649		)
Retail propane	21,477			21,696			(219		)
Refined products and renewables	28,958			(1,005		)	29,963
Corporate and other	(25,999		)	(14,681		)	(11,318		)
Operating income	$	18,079		$	41,169		$	(23,090	)

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Crude Oil Logistics

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

	Three Months Ended
	December 31,
	2014			2013			Change
	(in thousands)
Revenues:
Crude oil sales	$	1,683,989		$	1,319,290		$	364,699
Crude oil transportation and other	17,260			6,198			11,062
Total revenues (1)	1,701,249			1,325,488			375,761
Expenses:
Cost of sales	1,703,738			1,310,339			393,399
Operating expenses	10,070			14,336			(4,266		)
General and administrative expenses	3,625			1,410			2,215
Depreciation and amortization expense	10,630			5,827			4,803
Total expenses	1,728,063			1,331,912			396,151
Segment operating loss	$	(26,814	)	$	(6,424	)	$	(20,390	)

(1) Revenues include $6.4 million and $9.4 million of intersegment sales during the three months ended December 31, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues. Our crude oil logistics segment generated $1.7 billion of revenue from crude oil sales during the three months ended December 31, 2014, selling 22.7 million barrels at an average price of $74.32 per barrel. During the three months ended December 31, 2013, our crude oil logistics segment generated $1.3 billion of revenue from crude oil sales, selling 13.5 million barrels at an average price of $97.97 per barrel. The decrease in revenue per barrel is primarily due to the sharp decline in crude oil prices during the three months ended December 31, 2014.

Crude oil transportation and other revenues of our crude oil logistics segment were $17.3 million during the three months ended December 31, 2014, compared to $6.2 million of crude oil transportation and other revenues during the three months ended December 31, 2013. This increase was due primarily to the Gavilon Energy acquisition in December 2013.

Cost of Sales. Our cost of crude oil sold was $1.7 billion during the three months ended December 31, 2014, as we sold 22.7 million barrels at an average cost of $75.19 per barrel. Our cost of sales during the three months ended December 31, 2014 was increased by $7.0 million of net unrealized losses on derivatives and was reduced by $30.8 million of net realized gains on derivatives. During the three months ended December 31, 2013, our cost of crude oil sold was $1.3 billion, as we sold 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 net unrealized losses on derivatives and was reduced by $1.8 million of net realized gains on derivatives. The decrease in cost per barrel is primarily due to the sharp decline in crude oil prices during the three months ended December 31, 2014. This had an adverse impact on product margins, due to the difference in timing of when we purchase product and when we deliver it to the point of sale. We also recorded a lower of cost or market adjustment of $20.0 million at December 31, 2014.

The most significant driver of the increase in our sales volumes was the acquisition of Gavilon Energy in December 2013.

Operating Expenses. Our crude oil logistics segment incurred $10.1 million of operating expenses during the three months ended December 31, 2014, compared to $14.3 million of operating expenses during the three months ended December 31, 2013. The decrease was due primarily to lower incentive compensation expense (certain compensation otherwise payable in cash will instead be paid in common units, and as a result the related expense was recorded within “corporate and other,” rather than within the crude oil logistics segment), lower railcar lease expense as we purchased railcars beginning in January 2014 to utilize in our operations, lower repair and maintenance expense as a result of integration of acquisitions in prior periods, and lower relocation expenses.

General and Administrative Expenses. Our crude oil logistics segment incurred $3.6 million of general and administrative expenses during the three months ended December 31, 2014, compared to $1.4 million of general and administrative expenses during the three months ended December 31, 2013. This increase was due to the acquisitions of Gavilon Energy in December 2013 and TransMontaigne in July 2014. General and administrative expenses during the three months ended December 31, 2014 were increased by $1.4 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses were paid in December 2014. General and

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administrative expenses during the three months ended December 31, 2014 were also increased by $0.1 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense. Our crude oil logistics segment incurred $10.6 million of depreciation and amortization expense during the three months ended December 31, 2014, compared to $5.8 million of depreciation and amortization expense during the three months ended December 31, 2013. This increase was due primarily to acquisitions and capital expansions.

Water Solutions

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

	Three Months Ended
	December 31,						Change
	2014			2013			Acquisitions (1)		Other
	(in thousands)
Revenues:
Service fees	$	30,870		$	15,589		$	9,157	$	6,124
Recovered hydrocarbons	19,355			20,693			4,447		(5,785		)
Water transportation	16			5,490			—		(5,474		)
Total revenues	50,241			41,772			13,604		(5,135		)
Expenses:
Cost of sales - derivative (gain) loss (2)	(29,137		)	(541		)	—		(28,596		)
Cost of sales - other	52			3,112			—		(3,060		)
Operating expenses	26,373			18,866			8,924		(1,417		)
General and administrative expenses	641			1,095			47		(501		)
Depreciation and amortization expense	17,807			18,258			1,106		(1,557		)
Total expenses	15,736			40,790			10,077		(35,131		)
Segment operating income	$	34,505		$	982		$	3,527	$	29,996

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

(2) Includes realized and unrealized (gains) losses.

Revenues. Our water solutions segment generated $30.9 million of service fee revenue during the three months ended December 31, 2014, compared to $15.6 million of service fee revenue during the three months ended December 31, 2013. Of this increase, $9.2 million related to acquisitions. These acquired facilities took delivery of 14.8 million barrels of wastewater at an average revenue of $0.62 per barrel. The remaining increase of $6.1 million was due primarily to an increase in water volumes processed due to higher demand from customers. Exclusive of the acquisitions, our water solutions segment generated $21.7 million of service fee revenue during the three months ended December 31, 2014, taking delivery of 24.1 million barrels of wastewater at an average revenue of $0.90 per barrel. Our water solutions segment generated $15.6 million of service fee revenue during the three months ended December 31, 2013, taking delivery of 18.3 million barrels of wastewater at an average revenue of $0.85 per barrel. The average revenue per barrel varies across the basins we operate in due to differing regulatory requirements and market conditions among the basins.

Our water solutions segment generated $19.4 million of recovered hydrocarbon revenue during the three months ended December 31, 2014, compared to $20.7 million of recovered hydrocarbon revenue during the three months ended December 31, 2013. The decrease of $5.8 million was due primarily to lower crude oil prices during the three months ended December 31, 2014 as compared to the three months ended December 31, 2013, partially offset by an increase in water volumes processed due to higher demand from customers. Exclusive of the acquisitions, our water solutions segment generated $15.0 million of recovered hydrocarbon revenue during the three months ended December 31, 2014, taking delivery of 24.1 million barrels of wastewater at an average revenue of $0.62 per barrel. Our water solutions segment generated $20.7 million of recovered hydrocarbon revenue during the three months ended December 31, 2013, taking delivery of 18.3 million barrels of wastewater at an average revenue of $1.13 per barrel. This decrease was partially offset by an increase of $4.4 million related to acquisitions. These acquired facilities took delivery of 14.8 million barrels of wastewater at an average revenue of $0.30 per barrel.

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Our water solutions segment generated less than $0.1 million of water transportation revenue during the three months ended December 31, 2014, compared to $5.5 million of water transportation revenue during the three months ended December 31, 2013. During September 2014, we sold our water transportation business in order to focus our efforts on water processing.

Cost of Sales. We enter into derivatives in our water solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expect to recover when processing the wastewater. Our cost of sales was reduced by $5.5 million of net unrealized gains on derivatives and $23.6 million of net realized gains on derivatives during the three months ended December 31, 2014. Our cost of sales was reduced by $0.7 million of net unrealized gains on derivatives and increased by $0.2 million of net realized losses on derivatives during the three months ended December 31, 2013. In the table above, the full impact of the change in derivative gains and losses during the three months ended December 31, 2014 as compared to the three months ended December 31, 2013 is reported in the “other” column, as it is not possible to attribute these gains and losses to individual water treatment and disposal facilities. As of December 31, 2014, our water solutions business had open derivative contracts with scheduled settlement dates through March 2015. In December 2014, we settled derivative contracts that had scheduled settlement dates from April 2015 through September 2015, in order to lock in the gains on those derivatives.

Our other cost of sales was $0.1 million during the three months ended December 31, 2014, compared to $3.1 million during the three months ended December 31, 2013. This decrease was due primarily to the sale of our water transportation business during September 2014.

Operating Expenses. Our water solutions segment incurred $26.4 million of operating expenses during the three months ended December 31, 2014, compared to $18.9 million of operating expenses during the three months ended December 31, 2013. Of this increase, $8.9 million related to acquisitions. This increase was partially offset by a decrease of $1.4 million due primarily to the sale of our water transportation business during September 2014.

General and Administrative Expenses. Our water solutions segment incurred $0.6 million of general and administrative expenses during the three months ended December 31, 2014, compared to $1.1 million of general and administrative expenses during the three months ended December 31, 2013.

Depreciation and Amortization Expense. Our water solutions segment incurred $17.8 million of depreciation and amortization expense during the three months ended December 31, 2014, compared to $18.3 million of depreciation and amortization expense during the three months ended December 31, 2013. The decrease of $1.6 million was due primarily to the sale of our water transportation business during September 2014, which was partially offset by an increase of $0.6 million of amortization expense related to trade name intangible assets. During the year ended March 31, 2014, we ceased using certain trade names and began amortizing them as finite-lived defensive assets. This decrease was partially offset by an increase of $1.1 million related to acquisitions, which included $0.5 million of amortization expense related to trade name intangible assets.

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Liquids

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

	Three Months Ended
	December 31,
	2014			2013		Change
	(in thousands)
Revenues:
Propane sales	$	395,456		$	518,541	$	(123,085	)
Other product sales	329,814			336,654		(6,840		)
Other revenues	9,595			7,695		1,900
Total revenues (1)	734,865			862,890		(128,025		)
Expenses:
Cost of sales - propane	395,743			487,190		(91,447		)
Cost of sales - other products	306,147			314,102		(7,955		)
Cost of sales - other	4,889			6,577		(1,688		)
Operating expenses	7,348			9,513		(2,165		)
Loss on disposal of assets, net	29,886			361		29,525
General and administrative expenses	2,062			1,787		275
Depreciation and amortization expense	2,838			2,759		79
Total expenses	748,913			822,289		(73,376		)
Segment operating income (loss)	$	(14,048	)	$	40,601	$	(54,649	)

(1) Revenues include $49.8 million and $62.0 million of intersegment sales during the three months ended December 31, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues. Our liquids segment generated $395.5 million of wholesale propane sales revenue during the three months ended December 31, 2014, selling 380.5 million gallons at an average price of $1.04 per gallon. During the three months ended December 31, 2013, our liquids segment generated $518.5 million of wholesale propane sales revenue, selling 410.3 million gallons at an average price of $1.26 per gallon. Sales volumes were lower during the three months ended December 31, 2014 than during the three months ended December 31, 2013, due to lower demand resulting from warmer weather conditions.

Our liquids segment generated $329.8 million of other wholesale products sales revenue during the three months ended December 31, 2014, selling 230.3 million gallons at an average price of $1.43 per gallon. During the three months ended December 31, 2013, our liquids segment generated $336.7 million of other wholesale products sales revenue, selling 207.5 million gallons at an average price of $1.62 per gallon.

Cost of Sales. Our cost of wholesale propane sales was $395.7 million during the three months ended December 31, 2014, as we sold 380.5 million gallons at an average cost of $1.04 per gallon. Our cost of wholesale propane sales during the three months ended December 31, 2014 was increased by $6.5 million of net unrealized losses on derivatives. During the three months ended December 31, 2013, our cost of wholesale propane sales was $487.2 million, as we sold 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 net unrealized losses on derivatives.

Product margins per gallon of propane sold were lower during the three months ended December 31, 2014 than during the three months ended December 31, 2013. Prices declined sharply during the three months ended December 31, 2014 due to warmer weather conditions and declining crude oil prices. We use a weighted-average inventory costing method for our wholesale propane inventory, with the costing pools segregated based on the location of the inventory.

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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 declining prices, this can result in lower margins on these sales. We would generally expect the impact of these two different strategies being in the same inventory costing pools to even out over the course of a full fiscal year.

Our cost of sales of other products was $306.2 million during the three months ended December 31, 2014, as we sold 230.3 million gallons at an average cost of $1.33 per gallon. Our cost of sales of other products during the three months ended December 31, 2014 was increased by $0.3 million of net unrealized losses on derivatives. During the three months ended December 31, 2013, our cost of sales of other products was $314.1 million, as we sold 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 net unrealized gains on derivatives.

Operating Expenses. Our liquids segment incurred $37.2 million of operating expenses during the three months ended December 31, 2014, compared to $9.9 million of operating expenses during the three months ended December 31, 2013. This increase was due primarily to a loss on disposal of a natural gas liquids terminal of $29.9 million during the three months ended December 31, 2014.

General and Administrative Expenses. Our liquids segment incurred $2.1 million of general and administrative expenses during the three months ended December 31, 2014, compared to $1.8 million of general and administrative expenses during the three months ended December 31, 2013. This increase was due primarily to expanded operations.

Depreciation and Amortization Expense. Our liquids segment incurred $2.8 million of depreciation and amortization expense during the three months ended December 31, 2014 and the three months ended December 31, 2013.

Retail Propane

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

	Three Months Ended
	December 31,
	2014		2013		Change
	(in thousands)
Revenues:
Propane sales	$	99,859	$	112,570	$	(12,711	)
Distillate sales	29,102		37,648		(8,546		)
Other revenues	10,804		11,377		(573		)
Total revenues	139,765		161,595		(21,830		)
Expenses:
Cost of sales - propane	54,712		68,763		(14,051		)
Cost of sales - distillates	23,015		32,406		(9,391		)
Cost of sales - other	3,445		4,283		(838		)
Operating expenses	26,059		23,773		2,286
General and administrative expenses	3,108		3,330		(222		)
Depreciation and amortization expense	7,949		7,344		605
Total expenses	118,288		139,899		(21,611		)
Segment operating income	$	21,477	$	21,696	$	(219	)

Revenues. Our retail propane segment generated revenue of $99.9 million from propane sales during the three months ended December 31, 2014, selling 48.3 million gallons at an average price of $2.07 per gallon. During the three months ended December 31, 2013, our retail propane segment generated $112.6 million of revenue from propane sales, selling 50.6 million gallons at an average price of $2.22 per gallon. The decrease in volumes and average sales prices during the three months ended December 31, 2014 compared to the three months ended December 31, 2013 was due primarily to warmer weather conditions.

Our retail propane segment generated revenue of $29.1 million from distillate sales during the three months ended December 31, 2014, selling 9.4 million gallons at an average price of $3.10 per gallon. During the three months ended December 31, 2013, our retail propane segment generated $37.6 million of revenue from distillate sales, selling 10.4 million gallons at an average price of $3.61 per gallon.

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Cost of Sales. Our cost of retail propane sales was $54.7 million during the three months ended December 31, 2014, as we sold 48.3 million gallons at an average cost of $1.13 per gallon. During the three months ended December 31, 2013, our cost of retail propane sales was $68.8 million, as we sold 50.6 million gallons at an average cost of $1.36 per gallon.

Our cost of distillate sales was $23.0 million during the three months ended December 31, 2014, as we sold 9.4 million gallons at an average cost of $2.45 per gallon. During the three months ended December 31, 2013, our cost of distillate sales was $32.4 million, as we sold 10.4 million gallons at an average cost of $3.10 per gallon.

Operating Expenses. Our retail propane segment incurred $26.1 million of operating expenses during the three months ended December 31, 2014, compared to $23.8 million of operating expenses during the three months ended December 31, 2013. This increase was due primarily to acquisitions of retail propane businesses.

General and Administrative Expenses. Our retail propane segment incurred $3.1 million of general and administrative expenses during the three months ended December 31, 2014, compared to $3.3 million of general and administrative expenses during the three months ended December 31, 2013.

Depreciation and Amortization Expense. Our retail propane segment incurred $7.9 million of depreciation and amortization expense during the three months ended December 31, 2014, compared to $7.3 million of depreciation and amortization expense during the three months ended December 31, 2013.

Refined Products and Renewables

The following table summarizes the operating results of our refined products and renewables segment for the periods indicated. Our refined products and renewables segment began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne.

	Three Months Ended
	December 31,
	2014		2013			Change
	(in thousands)
Revenues:
Refined products sales (1)	$	1,833,090	$	252,154		$	1,580,936
Renewables sales	126,212		54,446			71,766
Service fees	24,746		—			24,746
Total revenues	1,984,048		306,600			1,677,448
Expenses:
Cost of sales - refined products	1,788,700		251,917			1,536,783
Cost of sales - renewables	116,925		54,433			62,492
Operating expenses	27,985		924			27,061
General and administrative expenses	11,692		—			11,692
Depreciation and amortization expense	9,788		331			9,457
Total expenses	1,955,090		307,605			1,647,485
Segment operating income (loss)	$	28,958	$	(1,005	)	$	29,963

(1) Revenues include $0.6 million of intersegment sales during the three months ended December 31, 2014 that are eliminated in our condensed consolidated statement of operations.

Revenues. Our refined products sales revenue was $1.8 billion during the three months ended December 31, 2014, selling 838.0 million gallons at an average price of $2.19 per gallon. Our refined products sales revenue was $252.2 million during the three months ended December 31, 2013, selling 89.1 million gallons at an average price of $2.83 per gallon.

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Our renewables sales revenue was $126.2 million during the three months ended December 31, 2014, selling 60.8 million gallons at an average price of $2.08 per gallon. Our renewables sales revenue was $54.4 million during the three months ended December 31, 2013, selling 21.5 million gallons at an average price of $2.53 per gallon.

Our refined products and renewables segment generated $24.7 million of service fee revenue during the three months ended December 31, 2014 which was due primarily to TLP’s refined products terminaling operations.

Cost of Sales. Our cost of refined products sales was $1.8 billion during the three months ended December 31, 2014, as we sold 838.0 million gallons at an average cost of $2.13 per gallon. Our cost of refined products sales was $251.9 million during the three months ended December 31, 2013, as we sold 89.1 million gallons at an average cost of $2.83 per gallon.

Our cost of renewables sales was $116.9 million during the three months ended December 31, 2014, as we sold 60.8 million gallons at an average cost of $1.92 per gallon. Our cost of renewables sales was $54.4 million during the three months ended December 31, 2013, as we sold 21.5 million gallons at an average cost of $2.53 per gallon. We use a weighted-average inventory costing method for our ethanol inventory. During periods of declining prices, our margins may be reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher.

During December 2014, a federal law was passed that enabled us to claim certain biodiesel tax credits for transactions during calendar year 2014. During the three months ended December 31, 2014, our cost of sales was reduced by $8.7 million related to these tax credits.

Operating Expenses. Our refined products and renewables segment incurred $28.0 million of operating expenses during the three months ended December 31, 2014, compared to $0.9 million of operating expenses during the three months ended December 31, 2013.

General and Administrative Expenses. Our refined products and renewables segment incurred $11.7 million of general and administrative expenses during the three months ended December 31, 2014. General and administrative expenses during the three months ended December 31, 2014 were increased by $0.1 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses were paid in December 2014. General and administrative expenses during the three months ended December 31, 2014 were also increased by $6.0 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense. Our refined products and renewables segment incurred $9.8 million of depreciation and amortization expense during the three months ended December 31, 2014, compared to $0.3 million of depreciation and amortization expense during the three months ended December 31, 2013.

Corporate and Other

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

	Three Months Ended
	December 31,
	2014			2013			Change
	(in thousands)
Equity-based compensation expense	$	(1,626	)	$	(4,078	)	$	2,452
Acquisition expenses	(665		)	(5,135		)	4,470
Other corporate expenses	(23,708		)	(5,468		)	(18,240		)
Total	$	(25,999	)	$	(14,681	)	$	(11,318	)

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The decrease in equity-based compensation expense during the three months ended December 31, 2014 as compared to the three months ended December 31, 2013 was due in part to fewer unvested units outstanding, and also to the fact that the market price of our common units declined during the three months ended December 31, 2014.

Acquisition expenses during the three months ended December 31, 2013 related primarily to the acquisition of Gavilon Energy.

The increase in other corporate expenses during the three months ended December 31, 2014 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. In addition, during January 2015, we reached an agreement with certain employees whereby certain bonus commitments otherwise payable in cash subsequent to our fiscal year end would instead be paid using our common units. Other corporate expenses during the three months ended December 31, 2014 include $13.2 million of this bonus expense, which if paid in cash, would have been reflected in expenses of the crude oil logistics, liquids, and refined products and renewables segments.

Segment Operating Results for the Nine Months Ended December 31, 2014 and 2013

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of Crescent and Cierra Marine in July 2013, and Gavilon Energy in December 2013. We expanded our water solutions business through numerous acquisitions of water disposal and transportation businesses, including Big Lake in July 2013, OWL in August 2013, Coastal in September 2013, and facilities acquired pursuant to development agreements. Our refined products and renewables businesses began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne. The results of operations of our liquids and retail propane segments are impacted by seasonality, due primarily to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our sales volumes and revenues. For these and other reasons, our results of operations for the nine months ended December 31, 2014 are not necessarily indicative of the results to be expected for future periods or for the full fiscal year ending March 31, 2015.

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Volumes

The following table summarizes the volume of product sold and water delivered during the nine months ended December 31, 2014 and 2013. Volumes shown in the following table include intersegment sales.

	Nine Months Ended
	December 31,
Segment	2014	2013	Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)	63,295	32,001	31,294

Water solutions
Water delivered (barrels)	90,657	44,753	45,904

Liquids
Propane sold (gallons)	804,520	721,120	83,400
Other products sold (gallons)	614,546	581,195	33,351

Retail propane
Propane sold (gallons)	95,466	94,615	851
Distillates sold (gallons)	18,093	18,618	(525	)

Refined products and renewables
Refined products sold (gallons)	2,059,949	89,063	1,970,886
Renewable products sold (gallons)	165,396	21,532	143,864

Operating Income (Loss) by Segment

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

	Nine Months Ended
	December 31,
Segment	2014			2013			Change
	(in thousands)
Crude oil logistics	$	(25,313	)	$	6,069		$	(31,382	)
Water solutions	48,390			6,938			41,452
Liquids	(4,032		)	53,091			(57,123		)
Retail propane	16,829			15,672			1,157
Refined products and renewables	36,525			(1,005		)	37,530
Corporate and other	(67,105		)	(36,993		)	(30,112		)
Operating income	$	5,294		$	43,772		$	(38,478	)

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Crude Oil Logistics

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

	Nine Months Ended
	December 31,
	2014			2013		Change
	(in thousands)
Revenues:
Crude oil sales	$	5,719,050		$	3,260,885	$	2,458,165
Crude oil transportation and other	42,456			25,927		16,529
Total revenues (1)	5,761,506			3,286,812		2,474,694
Expenses:
Cost of sales	5,704,896			3,228,215		2,476,681
Operating expenses	38,487			35,512		2,975
General and administrative expenses	13,835			3,175		10,660
Depreciation and amortization expense	29,601			13,841		15,760
Total expenses	5,786,819			3,280,743		2,506,076
Segment operating income (loss)	$	(25,313	)	$	6,069	$	(31,382	)

(1) Revenues include $26.2 million and $26.0 million of intersegment sales during the nine months ended December 31, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues. Our crude oil logistics segment generated $5.7 billion of revenue from crude oil sales during the nine months ended December 31, 2014, selling 63.3 million barrels at an average price of $90.36 per barrel. During the nine months ended December 31, 2013, our crude oil logistics segment generated $3.3 billion of revenue from crude oil sales, selling 32.0 million barrels at an average price of $101.90 per barrel. The decrease in revenue per barrel is primarily due to the sharp decline in crude oil prices during the three months ended December 31, 2014.

Crude oil transportation and other revenues of our crude oil logistics segment were $42.5 million during the nine months ended December 31, 2014, compared to $25.9 million of crude oil transportation and other revenues during the nine months ended December 31, 2013. This increase was due primarily to the Crescent and Cierra Marine acquisition in July 2013 and the Gavilon Energy acquisition in December 2013.

Cost of Sales. Our cost of crude oil sold was $5.7 billion during the nine months ended December 31, 2014, as we sold 63.3 million barrels at an average cost of $90.13 per barrel. Our cost of sales during the nine months ended December 31, 2014 was increased by $4.0 million of net unrealized losses on derivatives and was reduced by $26.8 million of net realized gains on derivatives. During the nine months ended December 31, 2013, our cost of crude oil sold was $3.2 billion, as we sold 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 net unrealized losses on derivatives and was reduced by less than $0.1 million of net realized gains on derivatives. The decrease in cost per barrel is primarily due to the sharp decline in crude oil prices during the three months ended December 31, 2014. This had an adverse impact on product margins, due to the difference in timing of when we purchase product and when we deliver it to the point of sale. We also recorded a lower of cost or market adjustment of $20.0 million at December 31, 2014.

The most significant driver of the increase in our sales volumes was the acquisition of Gavilon Energy in December 2013.

Operating Expenses. Our crude oil logistics segment incurred $38.5 million of operating expenses during the nine months ended December 31, 2014, compared to $35.5 million of operating expenses during the nine months ended December 31, 2013. This increase was due primarily to the Gavilon Energy acquisition in December 2013.

General and Administrative Expenses. Our crude oil logistics segment incurred $13.8 million of general and administrative expenses during the nine months ended December 31, 2014, compared to $3.2 million of general and administrative expenses during the nine months ended December 31, 2013. This increase was due to the acquisitions of Gavilon Energy in December 2013 and TransMontaigne in July 2014. General and administrative expenses during the nine months ended December 31, 2014 were increased by $5.6 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees,

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contingent upon successful completion of the sale of the business. These bonuses were paid in December 2014. General and administrative expenses during the nine months ended December 31, 2014 were also increased by $1.3 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense. Our crude oil logistics segment incurred $29.6 million of depreciation and amortization expense during the nine months ended December 31, 2014, compared to $13.8 million of depreciation and amortization expense during the nine months ended December 31, 2013. This increase was due primarily to acquisitions and capital expansions.

Water Solutions

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

	Nine Months Ended
	December 31,					Change
	2014			2013		Acquisitions (1)			Other
	(in thousands)
Revenues:
Service fees	$	72,809		$	42,864	$	18,646		$	11,299
Recovered hydrocarbons	66,704			40,929		20,633			5,142
Water transportation	10,761			12,682		1,454			(3,375		)
Total revenues	150,274			96,475		40,733			13,066
Expenses:
Cost of sales - derivative (gain) loss (2)	(34,207		)	280		—			(34,487		)
Cost of sales - other	6,256			6,656		1,160			(1,560		)
Operating expenses	75,121			42,876		28,717			3,528
General and administrative expenses	2,242			2,673		(110		)	(321		)
Depreciation and amortization expense	52,472			37,052		13,493			1,927
Total expenses	101,884			89,537		43,260			(30,913		)
Segment operating income	$	48,390		$	6,938	$	(2,527	)	$	43,979

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

(2) Includes realized and unrealized (gains) losses.

Revenues. Our water solutions segment generated $72.8 million of service fee revenue during the nine months ended December 31, 2014, compared to $42.9 million of service fee revenue during the nine months ended December 31, 2013. Of this increase, $18.6 million related to acquisitions, including our acquisitions of Big Lake, OWL, Coastal, and certain other water treatment and disposal facilities. The acquisitions generated $23.1 million of service fee revenue during the nine months ended December 31, 2014, taking delivery of 43.7 million barrels of wastewater at an average revenue of $0.53 per barrel. The acquisitions generated $4.5 million of service fee revenue during the nine months ended December 31, 2013, taking delivery of 11.1 million barrels of wastewater at an average revenue of $0.40 per barrel. The remaining increase of $11.3 million was due primarily to an increase in water volumes processed due to higher demand from customers. Exclusive of the acquisitions, our water solutions segment generated $49.7 million of service fee revenue during the nine months ended December 31, 2014, taking delivery of 47.0 million barrels of wastewater at an average revenue of $1.06 per barrel. Our water solutions segment generated $38.4 million of service fee revenue during the nine months ended December 31, 2013, taking delivery of 33.7 million barrels of wastewater at an average revenue of $1.14 per barrel. The average revenue per barrel varies across the basins we operate in due to differing regulatory requirements and market conditions among the basins.

Our water solutions segment generated $66.7 million of recovered hydrocarbon revenue during the nine months ended December 31, 2014, compared to $40.9 million of recovered hydrocarbon revenue during the nine months ended December 31, 2013. Of this increase, $20.6 million related to acquisitions, including our acquisitions of Big Lake, OWL, Coastal, and certain other water treatment and disposal facilities. The acquisitions generated $35.2 million of recovered hydrocarbon revenue during the nine months ended December 31, 2014, taking delivery of 43.7 million barrels of wastewater at an average revenue of $0.81 per barrel. The acquisitions generated $14.6 million of recovered hydrocarbon revenue during the nine months ended December 31, 2013, taking delivery of 11.1 million barrels of wastewater at an average revenue of $1.31 per barrel. The remaining increase of $5.1 million was

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due primarily to an increase in water volumes processed due to higher demand from customers. Exclusive of the acquisitions, our water solutions segment generated $31.5 million of recovered hydrocarbon revenue during the nine months ended December 31, 2014, taking delivery of 47.0 million barrels of wastewater at an average revenue of $0.67 per barrel. Our water solutions segment generated $26.3 million of recovered hydrocarbon revenue during the nine months ended December 31, 2013, taking delivery of 33.7 million barrels of wastewater at an average revenue of $0.78 per barrel.

Our water solutions segment generated $10.8 million of water transportation revenue during the nine months ended December 31, 2014, compared to $12.7 million of water transportation revenue during the nine months ended December 31, 2013. The decrease resulted from the sale of our water transportation business during September 2014 in order to focus our efforts on water processing.

Cost of Sales. We enter into derivatives in our water solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expect to recover when processing the wastewater. Our cost of sales was reduced by $12.1 million of net unrealized gains on derivatives and $22.1 million of net realized gains on derivatives during the nine months ended December 31, 2014. Our cost of sales was reduced by $1.0 million of net unrealized gains on derivatives and increased by $1.3 million of net realized losses on derivatives during the nine months ended December 31, 2013. In the table above, the full impact of the change in derivative gains and losses during the nine months ended December 31, 2014 as compared to the nine months ended December 31, 2013 is reported in the “other” column, as it is not possible to attribute these gains and losses to individual water treatment and disposal facilities. As of December 31, 2014, our water solutions business had open derivative contracts with scheduled settlement dates through March 2015. In December 2014, we settled derivative contracts that had scheduled settlement dates from April 2015 through September 2015, in order to lock in the gains on those derivatives.

Our other cost of sales was $6.3 million during the nine months ended December 31, 2014, compared to $6.7 million during the nine months ended December 31, 2013. These costs related primarily to our water transportation business, which we sold during September 2014 in order to focus our efforts on water processing.

Operating Expenses. Our water solutions segment incurred $75.1 million of operating expenses during the nine months ended December 31, 2014, compared to $42.9 million of operating expenses during the nine months ended December 31, 2013. Of this increase, $28.7 million related to acquisitions. The remaining increase of $3.5 million was due primarily to a loss of $4.0 million related to the sale of our water transportation business, partially offset by 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 from lightning strikes at two of our facilities.

General and Administrative Expenses. Our water solutions segment incurred $2.2 million of general and administrative expenses during the nine months ended December 31, 2014, compared to $2.7 million of general and administrative expenses during the nine months ended December 31, 2013.

Depreciation and Amortization Expense. Our water solutions segment incurred $52.5 million of depreciation and amortization expense during the nine months ended December 31, 2014, compared to $37.1 million of depreciation and amortization expense during the nine months ended December 31, 2013. Of this increase, $13.5 million related to acquisitions, which included $1.5 million of amortization expense related to trade name intangible assets. The remaining increase of $1.9 million was due primarily to $1.8 million of amortization expense related to trade name intangible assets. During the year ended March 31, 2014, we ceased using certain trade names and began amortizing them as finite-lived defensive assets.

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Liquids

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

	Nine Months Ended
	December 31,
	2014			2013		Change
	(in thousands)
Revenues:
Propane sales	$	858,335		$	833,815	$	24,520
Other product sales	924,798			895,113		29,685
Other revenues	22,125			25,809		(3,684		)
Total revenues (1)	1,805,258			1,754,737		50,521
Expenses:
Cost of sales - propane	845,379			789,298		56,081
Cost of sales - other products	880,671			855,179		25,492
Cost of sales - other	12,292			19,051		(6,759		)
Operating expenses	25,714			25,403		311
Loss on disposal of assets, net	29,768			3		29,765
General and administrative expenses	6,043			4,577		1,466
Depreciation and amortization expense	9,423			8,135		1,288
Total expenses	1,809,290			1,701,646		107,644
Segment operating income (loss)	$	(4,032	)	$	53,091	$	(57,123	)

(1) Revenues include $105.3 million and $108.0 million of intersegment sales during the nine months ended December 31, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues. Our liquids segment generated $858.3 million of wholesale propane sales revenue during the nine months ended December 31, 2014, selling 804.5 million gallons at an average price of $1.07 per gallon. During the nine months ended December 31, 2013, our liquids segment generated $833.8 million of wholesale propane sales revenue, selling 721.1 million gallons at an average price of $1.16 per gallon. The increase in volume was due to higher market demand earlier in the fiscal year, due in part to cold weather conditions during the previous winter.

Our liquids segment generated $924.8 million of other wholesale products sales revenue during the nine months ended December 31, 2014, selling 614.5 million gallons at an average price of $1.50 per gallon. During the nine months ended December 31, 2013, our liquids segment generated $895.1 million of other wholesale products sales revenue, selling 581.2 million gallons at an average price of $1.54 per gallon.

Cost of Sales. Our cost of wholesale propane sales was $845.4 million during the nine months ended December 31, 2014, as we sold 804.5 million gallons at an average cost of $1.05 per gallon. Our cost of wholesale propane sales during the nine months ended December 31, 2014 was increased by $8.1 million of net unrealized losses on derivatives. During the nine months ended December 31, 2013, our cost of wholesale propane sales was $789.3 million, as we sold 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 net unrealized losses on derivatives.

Product margins per gallon of propane sold were lower during the nine months ended December 31, 2014 than during the nine months ended December 31, 2013. Propane prices were high during the previous winter due to cold weather conditions, and prices declined during the current fiscal year due to warmer weather conditions and declining crude oil prices. We use a weighted-average inventory costing method for our wholesale propane inventory, with the costing pools segregated based on the location of the inventory.

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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 declining prices, this can result in lower margins on these sales. We would generally expect the impact of these two different strategies being in the same inventory costing pools to even out over the course of a full fiscal year.

Our cost of sales of other products was $880.7 million during the nine months ended December 31, 2014, as we sold 614.5 million gallons at an average cost of $1.43 per gallon. Our cost of sales of other products during the nine months ended December 31, 2014 was reduced by $0.5 million of net unrealized gains on derivatives. During the nine months ended December 31, 2013, our cost of sales of other products was $855.2 million, as we sold 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 net unrealized gains on derivatives.

Operating Expenses. Our liquids segment incurred $55.5 million of operating expenses during the nine months ended December 31, 2014, compared to $25.4 million of operating expenses during the nine months ended December 31, 2013. This increase was due primarily to a loss on disposal of a natural gas liquids terminal of $29.9 million during the nine months ended December 31, 2014.

General and Administrative Expenses. Our liquids segment incurred $6.0 million of general and administrative expenses during the nine months ended December 31, 2014, compared to $4.6 million of general and administrative expenses during the nine months ended December 31, 2013. This increase was due primarily to expanded operations.

Depreciation and Amortization Expense. Our liquids segment incurred $9.4 million of depreciation and amortization expense during the nine months ended December 31, 2014, compared to $8.1 million of depreciation and amortization expense during the nine months ended December 31, 2013.

Retail Propane

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

	Nine Months Ended
	December 31,
	2014		2013		Change
	(in thousands)
Revenues:
Propane sales	$	200,437	$	199,912	$	525
Distillate sales	59,327		66,079		(6,752		)
Other revenues	26,261		27,275		(1,014		)
Total revenues	286,025		293,266		(7,241		)
Expenses:
Cost of sales - propane	111,433		115,790		(4,357		)
Cost of sales - distillates	48,891		56,915		(8,024		)
Cost of sales - other	8,266		9,383		(1,117		)
Operating expenses	68,746		65,612		3,134
General and administrative expenses	8,656		8,439		217
Depreciation and amortization expense	23,204		21,455		1,749
Total expenses	269,196		277,594		(8,398		)
Segment operating income	$	16,829	$	15,672	$	1,157

Revenues. Our retail propane segment generated revenue of $200.4 million from propane sales during the nine months ended December 31, 2014, selling 95.5 million gallons at an average price of $2.10 per gallon. During the nine months ended December 31, 2013, our retail propane segment generated $199.9 million of revenue from propane sales, selling 94.6 million gallons at an average price of $2.11 per gallon.

Our retail propane segment generated revenue of $59.3 million from distillate sales during the nine months ended December 31, 2014, selling 18.1 million gallons at an average price of $3.28 per gallon. During the nine months ended December 31, 2013, our retail propane segment generated $66.1 million of revenue from distillate sales, selling 18.6 million gallons at an average price of $3.55 per gallon.

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Cost of Sales. Our cost of retail propane sales was $111.4 million during the nine months ended December 31, 2014, as we sold 95.5 million gallons at an average cost of $1.17 per gallon. During the nine months ended December 31, 2013, our cost of retail propane sales was $115.8 million, as we sold 94.6 million gallons at an average cost of $1.22 per gallon.

Our cost of distillate sales was $48.9 million during the nine months ended December 31, 2014, as we sold 18.1 million gallons at an average cost of $2.70 per gallon. During the nine months ended December 31, 2013, our cost of distillate sales was $56.9 million, as we sold 18.6 million gallons at an average cost of $3.06 per gallon.

Operating Expenses. Our retail propane segment incurred $68.7 million of operating expenses during the nine months ended December 31, 2014, compared to $65.6 million of operating expenses during the nine months ended December 31, 2013. The increase was due primarily to acquisitions of retail propane businesses.

General and Administrative Expenses. Our retail propane segment incurred $8.7 million of general and administrative expenses during the nine months ended December 31, 2014, compared to $8.4 million of general and administrative expenses during the nine months ended December 31, 2013.

Depreciation and Amortization Expense. Our retail propane segment incurred $23.2 million of depreciation and amortization expense during the nine months ended December 31, 2014, compared to $21.5 million of depreciation and amortization expense during the nine months ended December 31, 2013.

Refined Products and Renewables

	Nine Months Ended
	December 31,
	2014		2013			Change
	(in thousands)
Revenues:
Refined products sales (1)	$	5,285,824	$	252,154		$	5,033,670
Renewables sales	374,911		54,446			320,465
Service fees	48,030		—			48,030
Total revenues	5,708,765		306,600			5,402,165
Expenses:
Cost of sales - refined products	5,207,580		251,917			4,955,663
Cost of sales - renewables	363,209		54,433			308,776
Operating expenses	59,447		924			58,523
General and administrative expenses	19,455		—			19,455
Depreciation and amortization expense	22,549		331			22,218
Total expenses	5,672,240		307,605			5,364,635
Segment operating income (loss)	$	36,525	$	(1,005	)	$	37,530

(1) Revenues include $0.6 million of intersegment sales during the nine months ended December 31, 2014 that are eliminated in our condensed consolidated statement of operations.

Revenues. Our refined products sales revenue was $5.3 billion during the nine months ended December 31, 2014, selling 2.1 billion gallons at an average price of $2.57 per gallon. Our refined products sales revenue was $252.2 million during the nine months ended December 31, 2013, selling 89.1 million gallons at an average price of $2.83 per gallon.

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Our renewables sales revenue was $374.9 million during the nine months ended December 31, 2014, selling 165.4 million gallons at an average price of $2.27 per gallon. Our renewables sales revenue was $54.4 million during the nine months ended December 31, 2013, selling 21.5 million gallons at an average price of $2.53 per gallon.

Our refined products and renewables segment generated $48.0 million of service fee revenue during the nine months ended December 31, 2014 which was due primarily to TLP’s refined products terminaling operations.

Cost of Sales. Our cost of refined products sales was $5.2 billion during the nine months ended December 31, 2014, as we sold 2.1 billion gallons at an average cost of $2.53 per gallon. Our cost of refined products sales was $251.9 million during the nine months ended December 31, 2013, as we sold 89.1 million gallons at an average cost of $2.83 per gallon.

Our cost of renewables sales was $363.2 million during the nine months ended December 31, 2014, as we sold 165.4 million gallons at an average cost of $2.20 per gallon. Our cost of renewables sales was $54.4 million during the nine months ended December 31, 2013, as we sold 21.5 million gallons at an average cost of $2.53 per gallon. We use a weighted-average inventory costing method for our ethanol inventory. During periods of declining prices, our margins may be reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher.

During December 2014, a federal law was passed that enabled us to claim certain biodiesel tax credits for transactions during calendar year 2014. During the nine months ended December 31, 2014, our cost of sales was reduced by $8.7 million related to these tax credits.

Operating Expenses. Our refined products and renewables segment incurred $59.4 million of operating expenses during the nine months ended December 31, 2014, compared to $0.9 million of operating expenses during the nine months ended December 31, 2013.

General and Administrative Expenses. Our refined products and renewables segment incurred $19.5 million of general and administrative expenses during the nine months ended December 31, 2014. General and administrative expenses during the nine months ended December 31, 2014 were increased by $0.5 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses were paid in December 2014. General and administrative expenses during the nine months ended December 31, 2014 were also increased by $7.5 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense. Our refined products and renewables segment incurred $22.5 million of depreciation and amortization expense during the nine months ended December 31, 2014, compared to $0.3 million of depreciation and amortization expense during the nine months ended December 31, 2013.

Corporate and Other

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

	Nine Months Ended
	December 31,
	2014			2013			Change
	(in thousands)
Equity-based compensation expense	$	(23,285	)	$	(14,370	)	$	(8,915	)
Acquisition expenses	(4,993		)	(6,503		)	1,510
Other corporate expenses	(38,827		)	(16,120		)	(22,707		)
Total	$	(67,105	)	$	(36,993	)	$	(30,112	)

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The increase in equity-based compensation expense during the nine months ended December 31, 2014 is due primarily to $10.5 million of expense associated with restricted units granted in July 2014 to certain employees as a discretionary bonus that vested in September 2014.

Acquisition expenses during the nine months ended December 31, 2014 related primarily to the acquisition of TransMontaigne. Acquisition expenses during the nine months ended December 31, 2013 related primarily to the acquisition of Gavilon Energy.

The increase in other corporate expenses during the nine months ended December 31, 2014 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. In addition, during January 2015, we reached an agreement with certain employees whereby certain bonus commitments otherwise payable in cash subsequent to our fiscal year end would instead be paid using our common units. Other corporate expenses during the nine months ended December 31, 2014 include $13.2 million of this bonus expense, which if paid in cash, would have been reflected in expenses of the crude oil logistics, liquids, and refined products and renewables segments.

Operating loss during the nine months ended December 31, 2014 was increased by $0.4 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses were paid in December 2014. This amount is reported within “other corporate expenses” in the table above.

Other Income, Net

Other income, net for the three months and nine months ended December 31, 2014 includes $2.5 million of income related to the settlement of a contractual dispute.

Interest Expense

The largest component of interest expense during the three months and nine months ended December 31, 2014 and 2013 has been interest on our Revolving Credit Facility, the 2019 Notes, the 2021 Notes, the 2022 Notes, and the TLP Credit Facility (each as hereinafter defined). See Note 7 to our 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 and the applicable interest rates, as summarized below:

	Revolving Credit Facility				2019 Notes				2021 Notes				2022 Notes				TLP Credit Facility
	Average				Average				Average				Average				Average
	Balance		Average		Balance				Balance				Balance				Balance		Average
	Outstanding		Interest		Outstanding		Interest		Outstanding		Interest		Outstanding		Interest		Outstanding		Interest
	(in thousands)		Rate		(in thousands)		Rate		(in thousands)		Rate		(in thousands)		Rate		(in thousands)		Rate
Three Months Ended December 31,
2014	$	1,272,385	2.29	%	$	400,000	5.13	%	$	450,000	6.88	%	$	250,000	6.65	%	$	251,370	2.89	%
2013	464,370		3.09	%					376,630		6.88	%	250,000		6.65	%

Nine Months Ended December 31,
2014	$	1,082,624	2.33	%	$	254,545	5.13	%	$	450,000	6.88	%	$	250,000	6.65	%	$	249,060	2.66	%
2013	502,189		3.47	%					126,000		6.88	%	250,000		6.65	%

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

The increased level of debt outstanding during the three months and nine months ended December 31, 2014 was due primarily to borrowings to finance acquisitions.

Income Tax Provision (Benefit)

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Income tax benefit was $2.1 million during the three months ended December 31, 2014, compared to $0.5 million of income tax expense during the three months ended December 31, 2013. The increase in the income tax benefit was due primarily to the July 2014 acquisition of TransMontaigne, as TransMontaigne was subject to United States federal and state income taxes.

Income tax benefit was $3.0 million during the nine months ended December 31, 2014, compared to $0.4 million of income tax expense during the nine months ended December 31, 2013. The increase in the income tax benefit was due primarily to the July 2014 acquisition of TransMontaigne, as TransMontaigne was subject to United States federal and state income taxes.

Noncontrolling Interests

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

Net income attributable to noncontrolling interests was $5.6 million during the three months ended December 31, 2014, compared to $0.2 million during the three months ended December 31, 2013. The increase was due primarily to the July 2014 acquisition of TransMontaigne, in which we acquired the 2.0% general partner interest and a 19.7% limited partner interest in TLP.

Net income attributable to noncontrolling interests was $9.1 million during the nine months ended December 31, 2014, compared to $0.3 million during the nine months ended December 31, 2013. The increase was due primarily to the July 2014 acquisition of TransMontaigne, in which we acquired the 2.0% general partner interest and a 19.7% limited partner interest in TLP.

Seasonality

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

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 facilities. Our cash flows from operations are discussed below.

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

Our partnership agreement requires that, within 45 days after the end of each quarter we distribute all of our available cash (as defined in our partnership agreement) to unitholders as of the record date. Available cash for any quarter generally consists of all cash on hand at the end of that quarter, less the amount of cash reserves established by our general partner, to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any of our debt instruments or other agreements, and (iii) provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters. TLP’s partnership agreement also requires that, within 45 days after the end of each quarter it distribute all of its available cash (as defined in its partnership agreement) to its unitholders as of the record date.

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We believe that our anticipated cash flows from operations and the borrowing capacity under our revolving credit facility are sufficient to meet our liquidity needs. 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 common units to sellers of 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

At December 31, 2014, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

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At December 31, 2014, we were in compliance with the covenants under the purchase agreement and indenture governing the 2019 Notes.

2021 Notes

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2021 Notes, and the obligations under the 2021 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The purchase agreement and the indenture governing the 2021 Notes contain various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

At December 31, 2014, we were in compliance with the covenants under the purchase agreement and indenture governing the 2021 Notes.

2022 Notes

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(vii) consolidate or merge or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains similar leverage ratio and interest coverage ratio requirements to those of our Credit Agreement, which is described above.

At December 31, 2014, we were in compliance with the covenants under the Note Purchase Agreement.

TLP Credit Facility

Cash and cash equivalents	$	3,304
Accounts receivable - trade, net	10,310
Accounts receivable - affiliates	408
Inventories	1,591
Prepaid expenses and other current assets	1,474
Property, plant and equipment, net	475,950
Goodwill	38,576
Intangible assets, net	1,933
Investments in unconsolidated entities	260,694
Other noncurrent assets	1,670
Accounts payable - trade	(6,985		)
Accounts payable - affiliates	(128		)
Accrued expenses and other payables	(9,691		)
Advance payments received from customers	(144		)
Long-term debt	(252,000		)
Other noncurrent liabilities	(3,870		)
Net assets	$	523,092

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additional investments in BOSTCO). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 9, 2016.

At December 31, 2014, TLP had $252.0 million of outstanding borrowings under the TLP Credit Facility and no outstanding letters of credit.

Revolving Credit Balances

The following table summarizes revolving credit facility borrowings:

	Average
	Daily		Lowest		Highest
	Balance		Balance		Balance
	(in thousands)
Nine Months Ended December 31, 2014:
Expansion capital borrowings	$	350,284	$	114,000	$	620,000
Working capital borrowings	732,340		339,500		1,046,000
TLP credit facility borrowings (from July 1, 2014 through December 31, 2014)	249,060		228,000		259,700

Nine Months Ended December 31, 2013:
Expansion capital borrowings	$	366,796	$	—	$	546,000
Working capital borrowings	135,393		—		385,500

Cash Flows

The following table summarizes the sources (uses) of our cash flows:

	Nine Months Ended
	December 31,
Cash Flows Provided by (Used in):	2014			2013
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	(92,557	)	$	137,311
Changes in operating assets and liabilities	174,397			(72,538		)

Operating activities	$	81,840		$	64,773

Investing activities	(1,114,502		)	(1,371,988		)

Financing activities	1,052,778			1,304,555

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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 cash flows from operating activities. Increases in natural gas liquids prices typically reduce our operating cash flows due to higher cash requirements to fund increases in inventories, and decreases in natural gas liquids prices typically increase our operating cash flows 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 necessary during our first and second fiscal 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 borrowings under our revolving credit facilities.

During the nine months ended December 31, 2014, we paid $135.4 million for capital expenditures. Of this amount, $106.9 million represented expansion capital and $28.5 million represented maintenance capital (of this maintenance capital, approximately $2.9 million related to TLP). During the nine months ended December 31, 2013, we paid $107.9 million for capital expenditures. Of this amount, $83.3 million represented expansion capital and $24.6 million represented maintenance capital.

During the nine months ended December 31, 2014, we paid (i) $580.7 million to acquire TransMontaigne, (ii) $310.0 million to acquire RimRock’s 50% ownership interest in Grand Mesa, (iii) $195.6 million to acquire water treatment and disposal facilities, (iii) $15.0 million to acquire an interest in a water supply company, and (iv) $12.4 million to acquire retail propane businesses. During the nine months ended December 31, 2013, we completed a number of business combinations for which we paid $1,240.2 million of cash, net of cash acquired, on a combined basis. During the nine months ended December 31, 2014, we generated $190.5 million of investing cash flows from commodity derivatives. During the nine months ended December 31, 2013, we used $30.7 million of investing cash outflows related to commodity derivatives. During the nine months ended December 31, 2014 and 2013, we had contributions to unconsolidated entities of $33.5 million and $2.0 million, respectively. During the nine months ended December 31, 2014, we had other investments of $45.9 million related to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party.

Financing Activities. Changes in our cash flows from financing activities include borrowings from and repayments on our revolving credit facilities, 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 fiscal quarters), we may fund the cash flow deficits through our Working Capital Facility. During the nine months ended December 31, 2014, we borrowed $492.0 million on our revolving credit facilities (net of repayments) and issued the 2019 Notes for $400.0 million. During the nine months ended December 31, 2014, we received net proceeds of $370.4 million from the sale of our common units. During the nine months ended December 31, 2013, we borrowed $331.0 million on our Revolving Credit Facility (net of repayments) and issued the 2021 Notes for $450.0 million. During the nine months ended December 31, 2013, we received net proceeds of $650.2 million from the sale of our common units.

Cash flows from financing activities also include distributions paid to partners and noncontrolling interest owners. Based on the number of common units outstanding at December 31, 2014 (exclusive of unvested restricted units issued pursuant to employee and director compensation programs), if we made distributions equal to our minimum quarterly distribution of $0.3375 per unit ($1.35 annualized), total distributions would equal $29.9 million per quarter ($119.7 million per year). To the extent our cash flows from operating activities are not sufficient to finance our required distributions, we may be required to increase borrowings under our Working Capital Facility.

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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
April 24, 2014	May 5, 2014	May 15, 2014	0.5513		43,737		5,754
July 24, 2014	August 4, 2014	August 14, 2014	0.5888		52,036		9,481
October 23, 2014	November 4, 2014	November 14, 2014	0.6088		53,902		11,141
January 26, 2015	February 6, 2015	February 13, 2015	0.6175		54,684		11,860

Distributions to noncontrolling interest partners are primarily comprised of distributions that TLP is required to make within 45 days after the end of each quarter to its unitholders as of the record date. To the extent TLP’s cash flows from operating activities are not sufficient to finance its required distributions, it may be required to increase borrowings under the TLP Credit Facility.

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Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2014 for our fiscal years ending thereafter:

			Three Months
			Ending
			March 31,		Years Ending March 31,
	Total		2015		2016		2017		2018		Thereafter
	(in thousands)
Principal payments on long-term debt —
Expansion capital borrowings	$	598,000	$	—	$	—	$	—	$	—	$	598,000
Working capital borrowings	798,000		—		—		—		—		798,000
2019 Notes	400,000		—		—		—		—		400,000
2021 Notes	450,000		—		—		—		—		450,000
2022 Notes	250,000		—		—		—		25,000		225,000
TLP Credit Facility	252,000		—		252,000		—		—		—
Other long-term debt	9,777		1,026		3,187		2,398		1,505		1,661
Interest payments on long-term debt —
Revolving Credit Facility (1)	140,429		9,119		36,475		36,475		36,475		21,885
2019 Notes	102,500		10,250		20,500		20,500		20,500		30,750
2021 Notes (2)	217,013		—		31,388		30,938		30,938		123,749
2022 Notes	87,281		4,156		16,625		16,625		16,209		33,666
TLP Credit Facility	4,192		1,676		2,516		—		—		—
Other long-term debt	537		83		211		127		80		36
Letters of credit	176,101		—		—		—		—		176,101
Future minimum lease payments under other noncancelable operating leases	500,055		34,633		111,286		93,153		78,683		182,300
Future minimum throughput payments under noncancelable agreements (3)	382,454		23,199		89,365		53,750		53,831		162,309
Grand Mesa construction commitment (4)	647,915		—		647,915		—		—		—
Fixed-price commodity purchase commitments	51,807		30,753		21,054		—		—		—
Index-price commodity purchase commitments (5)	397,697		369,719		27,978		—		—		—
Total contractual obligations	$	5,465,758	$	484,614	$	1,260,500	$	253,966	$	263,221	$	3,203,457

Purchase commitments (thousands):
Natural gas liquids fixed-price (gallons) (6)	60,493		28,628		31,865		—		—		—
Natural gas liquids index-price (gallons) (6)	312,125		256,702		55,423		—		—		—
Crude oil index-price (barrels) (6)	4,796		4,796		—		—		—		—

(1) The estimated interest payments on our revolving credit facilities are based on principal and letters of credit outstanding at December 31, 2014. See Note 7 to our condensed consolidated financial statements included in this Quarterly Report for additional information on our revolving credit facilities.

(2) Interest payments for the fiscal year ending March 31, 2016 include $0.5 million of liquidated damages resulting from a delay in completing an exchange offer.

(3) At December 31, 2014, we had agreements with crude oil and refined products pipeline operators obligating us to minimum throughput payments in exchange for pipeline capacity commitments.

(4) Construction on the Grand Mesa pipeline began in October 2014. We anticipate that the pipeline will commence service in late 2016. The majority of the costs associated with this project will be made during the fiscal year ending March 31, 2016.

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(5) Index prices are based on a forward price curve at December 31, 2014. A theoretical change of $0.10 per gallon in the underlying commodity price at December 31, 2014 would result in a change of $31.2 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel in the underlying commodity price at December 31, 2014 would result in a change of $4.8 million in the value of our index-price crude oil purchase commitments.

(6) At December 31, 2014, we had the following sales contract volumes (in thousands):

Natural gas liquids fixed-price (gallons)		221,370
Natural gas liquids index-price (gallons)		190,516
Crude oil index-price (barrels)		4,615

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 fiscal year ended March 31, 2014 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 can fluctuate widely based on 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. Crude oil prices declined sharply during the six months ended December 31, 2014 (the spot price for NYMEX West Texas Intermediate crude oil at Cushing, Oklahoma declined from $105.34 per barrel at July 1, 2014 to $53.27 per barrel at December 31, 2014). While crude oil production in the United States has been strong in recent years, the steep decline in crude oil prices has reduced the incentive for producers to expand production. Several major producers have reported that they plan to reduce their capital expansion budgets, and several oilfield services companies have announced reductions in staffing. Various media outlets have reported that, with prices at current levels, it may become uneconomical to drill new crude oil wells in certain basins. If crude oil prices remain low, declines in crude oil production may adversely impact volumes in our crude oil logistics business.

As of December 31, 2014, crude oil markets were in contango (a condition in which the forward crude price is greater than the spot price). During most of the last two years, crude oil markets were backwardated (a condition in which the forward crude price is lower than the spot price). Our crude oil logistics business benefits when the market is in contango, as increasing prices result in inventory holding gains during the time between when we purchase inventory and when we sell it. In addition, we are more likely to be able to utilize our storage assets when crude oil markets are in contango.

Water Solutions

Our opportunity to generate 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. As described above, crude oil prices declined sharply in recent months. At current market prices, producers are likely to reduce drilling activity, which could have an adverse impact on the volumes of our water solutions business.

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A portion of the revenues of our water solutions business are generated from the sale of crude oil that we recover in the process of treating the wastewater. Because of this, lower crude prices result in lower per-barrel revenues for our water solutions business.

Liquids

The volumes we sell in our wholesale natural gas liquids business are heavily dependent on the demand for propane and butane, which is influenced by weather conditions and gasoline blending. During years when demand is higher during the winter months, we have the opportunity to utilize our storage assets to increase margins.

Weather conditions were warmer during the three months ended December 31, 2014 than during the three months ended December 31, 2013, which reduced demand for natural gas liquids. This, combined with falling crude prices, caused the price of propane and butane to decline significantly (the spot price for propane at Conway, Kansas decreased from $1.07 per gallon on October 1, 2014 to $0.42 per gallon on December 31, 2014). We use a weighted-average inventory costing method for our wholesale propane inventory, with the costing pools segregated based on the location of the inventory. During periods of declining prices, our margins are typically reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher.

Retail Propane

The volumes we sell in our retail propane business are heavily dependent on the demand for propane, which is influenced by weather conditions. Weather conditions were warmer during the three months ended December 31, 2014 than during the three months ended December 31, 2013, which reduced demand for propane. This, combined with falling crude prices, caused the price of propane to decline significantly.

Product margins in the retail propane industry tend to be higher when wholesale propane prices are low, and volumes tend to increase when the price to the consumer is lower.

Refined Products

During the three months ended December 31, 2014, refined product prices decreased considerably (the spot price for NYMEX gasoline prompt-month futures decreased from $2.45 per gallon on October 1, 2014 to $1.44 per gallon on December 31, 2014). The decline in refined product prices was due primarily to a decline in the price of crude oil.

We use a weighted-average inventory costing method for our refined products inventory, with the costing pools segregated based on the location of the inventory. During periods of declining prices, our margins may be reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” ASU No. 2014-09 will replace most existing revenue recognition guidance in GAAP. The core principle of this ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU is effective for the Partnership beginning April 1, 2017, and allows for both full retrospective and modified retrospective (with cumulative effect) methods of adoption. We are in the process of determining the method of adoption and assessing the impact of this ASU on our consolidated financial statements.

Critical Accounting Policies

The preparation of financial statements and related disclosures in compliance with GAAP requires the selection and application of appropriate accounting principles to the relevant facts and circumstances of the Partnership’s operations and the use of estimates made by management. We have identified the following accounting policies that are most important to the portrayal of our financial condition and results of operations. The application of these accounting policies, which requires subjective or complex

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judgments regarding estimates and projected outcomes of future events, and changes in these accounting policies, could have a material effect on our consolidated financial statements.

Revenue Recognition

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

Impairment of Long-Lived Assets

Goodwill is subject to at least an annual assessment for impairment. We perform our annual assessment of impairment during the fourth quarter of our fiscal year, and more frequently if circumstances warrant. To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting unit exceeds its carrying amount. 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.

Crude oil spot and forward prices have decreased significantly in recent months, and we expect this to have an unfavorable impact on the revenues of our water solutions business. The volume of water we process is driven in part by the level of crude oil production, and the lower crude oil prices have given producers less incentive to expand production. In addition, a significant portion of the revenues of our water solutions business are generated from the sale of crude oil that we recover in the process of treating the wastewater, and lower crude oil prices have an adverse impact on these revenues. We will consider these factors in preparing our goodwill impairment assessment during the fourth quarter of our fiscal year. If we conclude that any of our goodwill is impaired, we will record a reduction to goodwill and a related impairment expense in the fourth quarter of our fiscal year ending March 31, 2015.

We evaluate property, plant and equipment and amortizable intangible assets for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is less than its carrying value.

We evaluate equity method investments for impairment when we believe the current fair value may be less than the carrying amount. We record impairments of equity method investments if we believe the decline in value is other than temporary.

Asset Retirement Obligations

We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value can be made. In order to determine the fair value of such a liability, we must make certain estimates and assumptions including, among other things, projected cash flows, the estimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time. We have recorded a liability of $3.1 million at December 31, 2014. This liability is related to water treatment and disposal facilities and crude oil facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

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regulations, after taking into consideration the estimated lives of our facilities, is material to our consolidated financial position or results of operations.

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

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

Amortization of Intangible Assets

Amortization expense represents the systematic write-off of the cost of our amortizable intangible assets to the results of operations for the quarterly and annual periods during which the assets are used. We amortize the majority of these intangible assets using the straight-line method, which results in us recording amortization expense evenly over the estimated life of the individual asset. The estimate of amortization expense requires us to make assumptions regarding the useful economic lives of our assets. At the time we acquire intangible assets, we develop assumptions about the useful economic lives of such assets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our amortization expense prospectively. Examples of such circumstances include changes in customer attrition rates and changes in laws and regulations that could limit the estimated economic life of an asset.

Business Combinations

We have made in the past, and expect to make in the future, acquisitions of other businesses. We record business combinations using the “acquisition method,” in which the assets acquired and liabilities assumed are recorded at their acquisition date fair values. Fair values of assets acquired and liabilities assumed are based upon available information and may involve us engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identify and include in the allocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property, plant and equipment and intangible assets, including those with indefinite lives. The estimates also include the fair value of contracts including commodity purchase and sale agreements, storage and transportation contracts, and employee compensation commitments. The excess of the purchase price over the net fair value of acquired assets and assumed liabilities is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination. The impact of subsequent changes to the identification of assets and liabilities may require retrospective adjustments to our previously-reported consolidated financial position and results of operations.

Inventories

Our inventories consist primarily of crude oil, natural gas liquids, refined products, ethanol, and biodiesel. The market values of these commodities change on a daily basis as supply and demand conditions change. We value our inventories at the lower of cost or market, with cost determined using either the weighted-average cost or the first in, first out (FIFO) methods, including the cost of transportation and storage. Market is determined based on estimated replacement cost using prices at the end of the period. At the end of each fiscal year, we also perform a “lower of cost or market” analysis; if the cost basis of the inventories would not be recoverable based on market prices at the end of the year, we reduce the book value of the inventories to the recoverable amount. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business to sell the inventory in retail markets. When performing this analysis during interim periods within a fiscal year, accounting standards do not require us to record a lower of cost or market write-down if we expect the market values to recover by our fiscal year end of March 31. We are unable to control changes in the market value of these commodities and are unable to determine whether write-downs will be required in future periods. In addition, write-downs at interim periods could be required if we cannot conclude that market values will recover sufficiently by our fiscal year end.

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Equity-Based Compensation

Our general partner has granted certain restricted units to employees and directors under a long-term incentive plan. These units vest in tranches, subject to the continued service of the recipients.

We report unvested units as liabilities on our condensed consolidated balance sheets. When units vest and are issued, we record an increase to equity.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

At December 31, 2014, a significant portion of our long-term debt is variable-rate debt. Changes in interest rates impact the interest payments of our variable-rate debt but generally do not impact the fair value of the liability. Conversely, changes in interest rates impact the fair value of the fixed-rate debt but do not impact its cash flows.

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, natural gas liquids, and refined products 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.

Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, restrictions on product liftings, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions, as deemed appropriate. The principal counterparties associated with our operations at December 31, 2014 were retailers, resellers, energy marketers, producers, refiners and dealers.

The natural gas liquids and crude oil industries are “margin-based” and “cost-plus” businesses in which gross profits depend on the differential of sales prices over supply costs. As a result, our profitability may be impacted by changes in wholesale prices of natural gas liquids and crude oil. When there are sudden and sharp increases in the wholesale cost of natural gas liquids and crude oil, we may not be able to pass on these increases to our customers through retail or wholesale prices. Natural gas liquids and crude oil are

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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. We may experience net unbalanced positions from time to time. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio.

Although we use derivative commodity instruments to reduce the market price risk associated with forecasted transactions, we have not accounted for such derivative commodity instruments as hedges. We record the changes in fair value of these derivative commodity instruments within cost of sales. The following table summarizes the hypothetical impact on the December 31, 2014 fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands):

	Increase
	(Decrease)
	To Fair Value
Crude oil (crude oil logistics segment)	$	(4,562	)
Crude oil (water solutions segment)	(1,456		)
Propane (liquids segment)	584
Other products (liquids segment)	555
Refined products (refined products and renewables segment)	(29,972		)
Renewables (refined products and renewables segment)	(62		)

Fair Value

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

Item 4. Controls and Procedures

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

We completed an evaluation under the supervision and with participation of our management, including the principal executive officer and principal financial officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures at December 31, 2014. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of December 31, 2014, 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 acquisitions of Gavilon Energy or TransMontaigne, 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, 2014 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

We acquired Gavilon Energy in December 2013 and TransMontaigne in July 2014, as described in Note 4 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 operations will continue into future fiscal quarters.

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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 1, of this Quarterly Report, which information is incorporated by reference into this Item 1.

Item 1A. Risk Factors

As described in our Annual Report on Form 10-K for the year ended March 31, 2014 and in this Quarterly Report, our business is impacted by changes in commodity prices. Crude oil prices have declined significantly in recent months, which could have an adverse impact on our water solutions business, as summarized in the risk factor below. Except as set forth below, there have been no material changes in 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, 2014, as supplemented and updated by Part II, Item 1A “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2014.

Declining crude oil prices could adversely impact our water solutions business.

Crude oil spot and forward prices have decreased significantly in recent months, and we expect this to have an unfavorable impact on the revenues of our water solutions business. The volume of water we process is driven in part by the level of crude oil production, and the lower crude oil prices have given producers less incentive to expand production. In addition, a significant portion of the revenues of our water solutions business are generated from the sale of crude oil that we recover in the process of treating the wastewater, and lower crude oil prices have an adverse impact on these revenues. A further decline in crude oil prices or a prolonged period of low crude oil prices could have an adverse effect on our water solutions business.

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

None.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit Number		Exhibit

4.1		Amendment No. 7 to Note Purchase Agreement, dated as of December 19, 2014 and effective as of December 26, 2014, 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 on January 2, 2015)
10.1		Facility Increase Agreement, dated December 1, 2014, 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 on December 1, 2014)
10.2		Amendment No. 8 to Credit Agreement, dated as of December 19, 2014 and effective as of December 26, 2014, 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 on January 2, 2015)
12.1	*	Computation of ratios of earnings to fixed charges
31.1	*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	**	XBRL Instance Document
101.SCH	**	XBRL Schema Document
101.CAL	**	XBRL Calculation Linkbase Document
101.DEF	**	XBRL Definition Linkbase Document
101.LAB	**	XBRL Label Linkbase Document
101.PRE	**	XBRL Presentation Linkbase Document

	*	Exhibits filed with this report.

	**	The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets at December 31, 2014 and March 31, 2014, (ii) Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2014 and 2013, (iii) Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and nine months ended December 31, 2014 and 2013, (iv) Condensed Consolidated Statement of Changes in Equity for the nine months ended December 31, 2014, (v) Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2014 and 2013, 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 9, 2015		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer

Date: February 9, 2015		By:	/s/ Atanas H. Atanasov
			Atanas H. Atanasov
			Chief Financial Officer

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EXHIBIT INDEX

Exhibit Number		Exhibit

4.1		Amendment No. 7 to Note Purchase Agreement, dated as of December 19, 2014 and effective as of December 26, 2014, 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 on January 2, 2015)
10.1		Facility Increase Agreement, dated December 1, 2014, 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 on December 1, 2014)
10.2		Amendment No. 8 to Credit Agreement, dated as of December 19, 2014 and effective as of December 26, 2014, 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 on January 2, 2015)
12.1	*	Computation of ratios of earnings to fixed charges
31.1	*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	**	XBRL Instance Document
101.SCH	**	XBRL Schema Document
101.CAL	**	XBRL Calculation Linkbase Document
101.DEF	**	XBRL Definition Linkbase Document
101.LAB	**	XBRL Label Linkbase Document
101.PRE	**	XBRL Presentation Linkbase Document

	*		Exhibits filed with this report.

	**		The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets at December 31, 2014 and March 31, 2014, (ii) Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2014 and 2013, (iii) Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and nine months ended December 31, 2014 and 2013, (iv) Condensed Consolidated Statement of Changes in Equity for the nine months ended December 31, 2014, (v) Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2014 and 2013, and (vi) Notes to Condensed Consolidated Financial Statements.