Edgar Filing: NGL Energy Partners LP

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended December 31, 2017

¨ 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 ¨

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 (§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 ¨

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



Large accelerated filer x		Accelerated filer ¨
Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company ¨
Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

At February 5, 2018, there were 121,083,664 common units issued and outstanding.

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PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements	3
	Unaudited Condensed Consolidated Balance Sheets at December 31, 2017 and March 31, 2017	3
	Unaudited Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2017 and 2016	4
	Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and nine months ended December 31, 2017 and 2016	5
	Unaudited Condensed Consolidated Statement of Changes in Equity for the nine months ended December 31, 2017	6
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2017 and 2016	7
	Notes to Unaudited Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	50
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	87
Item 4.	Controls and Procedures	88
PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	89
Item 1A.	Risk Factors	89
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	89
Item 3.	Defaults Upon Senior Securities	89
Item 4.	Mine Safety Disclosures	89
Item 5.	Other Information	89
Item 6.	Exhibits	90
SIGNATURES		91

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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. Certain words in this Quarterly Report 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, identify forward-looking statements. Although we and our general partner believe such forward-looking statements are reasonable, neither we nor our general partner can assure they 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 expected. Among the key risk factors that may affect our consolidated financial position and results of operations are:


•	the prices of crude oil, natural gas liquids, gasoline, diesel, ethanol, and biodiesel;


•	energy prices generally;


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


•	the general level of demand, and the availability of supply, for crude oil, natural gas liquids, gasoline, diesel, ethanol, and biodiesel;


•	the level of crude oil and natural gas drilling and production in areas where we have water treatment and disposal facilities;


•	the prices of propane and distillates relative to the prices of alternative and competing fuels;


•	the price of gasoline relative to the price of corn, which affects the price of ethanol;


•	the ability to obtain adequate supplies of products if an interruption in supply or transportation occurs and the availability of capacity to transport products to market areas;


•	actions taken by foreign oil and gas producing nations;


•	the political and economic stability of foreign oil and gas producing nations;


•	the effect of weather conditions on supply and demand for crude oil, natural gas liquids, gasoline, diesel, ethanol, and biodiesel;


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


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


•	the availability, price, and marketing of competing fuels;


•	the effect of energy conservation efforts on product demand;


•	energy efficiencies and technological trends;


•	governmental regulation and taxation;


•	the effect of legislative and regulatory actions on hydraulic fracturing, wastewater disposal, and the treatment of flowback and produced water;


•	hazards or operating risks related to transporting and distributing petroleum products that may not be fully covered by insurance;


•	the maturity of the crude oil, natural gas liquids, and refined products industries and competition from other marketers;


•	loss of key personnel;


•	the ability to renew contracts with key customers;


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


•	the ability to renew leases for our leased equipment and storage facilities;


•	the nonpayment or nonperformance by our counterparties;

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•	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 complete accretive acquisitions, and integrate acquired assets and businesses;


•	changes in the volume of hydrocarbons 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 applicable laws and regulations, including tax, environmental, transportation, and employment regulations, or new interpretations by regulatory agencies concerning such laws and regulations and the effect of such laws and regulations (now existing or in the future) on our business operations;


•	the costs and effects of legal and administrative proceedings;


•	any reduction or the elimination of the federal Renewable Fuel Standard; 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 may be 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 discussed under Part I, Item 1A–“Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended March 31, 2017 and under Part II, Item 1A–“Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2017.

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PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Balance Sheets

(in Thousands, except unit amounts)



	December 31, 2017			March 31, 2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	28,469		$	12,264
Accounts receivable-trade, net of allowance for doubtful accounts of $5,561 and $5,234, respectively	1,063,907			800,607
Accounts receivable-affiliates	3,517			6,711
Inventories	645,100			561,432
Prepaid expenses and other current assets	97,395			103,193
Assets held for sale	131,591			—
Total current assets	1,969,979			1,484,207
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $420,174 and $375,594, respectively	1,708,683			1,790,273
GOODWILL	1,313,317			1,451,716
INTANGIBLE ASSETS, net of accumulated amortization of $455,532 and $414,605, respectively	1,064,955			1,163,956
INVESTMENTS IN UNCONSOLIDATED ENTITIES	16,369			187,423
LOAN RECEIVABLE-AFFILIATE	318			3,200
OTHER NONCURRENT ASSETS	242,765			239,604
Total assets	$	6,316,386		$	6,320,379
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	866,768		$	658,021
Accounts payable-affiliates	474			7,918
Accrued expenses and other payables	230,752			207,125
Advance payments received from customers	46,850			35,944
Current maturities of long-term debt	3,260			29,590
Liabilities held for sale	16,574			—
Total current liabilities	1,164,678			938,598
LONG-TERM DEBT, net of debt issuance costs of $22,883 and $33,458, respectively, and current maturities	2,921,966			2,963,483
OTHER NONCURRENT LIABILITIES	168,281			184,534
COMMITMENTS AND CONTINGENCIES (NOTE 9)

CLASS A 10.75% CONVERTIBLE PREFERRED UNITS, 19,942,169 and 19,942,169 preferred units issued and outstanding, respectively	76,056			63,890
REDEEMABLE NONCONTROLLING INTEREST	4,011			3,072

EQUITY:
General partner, representing a 0.1% interest, 121,205 and 120,300 notional units, respectively	(50,869		)	(50,529		)
Limited partners, representing a 99.9% interest, 121,083,664 and 120,179,407 common units issued and outstanding, respectively	1,823,740			2,192,413
Class B preferred limited partners, 8,400,000 and 0 preferred units issued and outstanding, respectively	202,731			—
Accumulated other comprehensive loss	(1,478		)	(1,828		)
Noncontrolling interests	7,270			26,746
Total equity	1,981,394			2,166,802
Total liabilities and equity	$	6,316,386		$	6,320,379

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Operations

(in Thousands, except unit and per unit amounts)



	Three Months Ended December 31,						Nine Months Ended December 31,
	2017			2016			2017			2016
REVENUES:
Crude Oil Logistics	$	585,007		$	385,906		$	1,526,944		$	1,161,742
Water Solutions	64,024			40,359			162,023			115,845
Liquids	709,044			470,275			1,379,981			909,584
Retail Propane	160,025			128,654			291,797			240,131
Refined Products and Renewables	2,944,874			2,381,283			8,806,717			6,746,168
Other	289			164			696			679
Total Revenues	4,463,263			3,406,641			12,168,158			9,174,149
COST OF SALES:
Crude Oil Logistics	552,871			361,839			1,423,511			1,107,587
Water Solutions	10,192			477			13,019			3,871
Liquids	670,701			430,946			1,319,344			831,221
Retail Propane	87,487			60,508			148,443			106,019
Refined Products and Renewables	2,951,440			2,374,175			8,781,009			6,674,194
Other	117			77			311			300
Total Cost of Sales	4,272,808			3,228,022			11,685,637			8,723,192
OPERATING COSTS AND EXPENSES:
Operating	84,846			76,981			237,285			225,408
General and administrative	29,218			18,280			77,689			88,077
Depreciation and amortization	63,340			60,767			192,427			160,276
(Gain) loss on disposal or impairment of assets, net	(111,480		)	34			(11,242		)	(203,433		)
Revaluation of liabilities	—			—			5,600			—
Operating Income (Loss)	124,531			22,557			(19,238		)	180,629
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	3,426			1,279			7,270			1,726
Revaluation of investments	—			—			—			(14,365		)
Interest expense	(51,790		)	(41,436		)	(151,249		)	(105,316		)
(Loss) gain on early extinguishment of liabilities, net	(21,141		)	—			(22,479		)	30,890
Other income, net	2,107			20,007			6,113			25,860
Income (Loss) Before Income Taxes	57,133			2,407			(179,583		)	119,424
INCOME TAX EXPENSE	(364		)	(1,114		)	(934		)	(2,036		)
Net Income (Loss)	56,769			1,293			(180,517		)	117,388
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(89		)	(317		)	(221		)	(6,091		)
LESS: NET (INCOME) LOSS ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS	(424		)	—			261			—
NET INCOME (LOSS) ATTRIBUTABLE TO NGL ENERGY PARTNERS LP	56,256			976			(180,477		)	111,297
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS	(16,219		)	(8,906		)	(42,001		)	(20,958		)
LESS: NET (INCOME) LOSS ALLOCATED TO GENERAL PARTNER	(73		)	(22		)	121			(180		)
LESS: REPURCHASE OF WARRANTS	—			—			(349		)	—
NET INCOME (LOSS) ALLOCATED TO COMMON UNITHOLDERS	$	39,964		$	(7,952	)	$	(222,706	)	$	90,159
BASIC INCOME (LOSS) PER COMMON UNIT	$	0.33		$	(0.07	)	$	(1.84	)	$	0.85
DILUTED INCOME (LOSS) PER COMMON UNIT	$	0.32		$	(0.07	)	$	(1.84	)	$	0.82
BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	120,844,008			107,966,901			120,899,502			106,114,668
DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	124,161,966			107,966,901			120,899,502			109,554,928

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)

(in Thousands)



	Three Months Ended December 31,				Nine Months Ended December 31,
	2017		2016		2017			2016
Net income (loss)	$	56,769	$	1,293	$	(180,517	)	$	117,388
Other comprehensive income	784		545		350			60
Comprehensive income (loss)	$	57,553	$	1,838	$	(180,167	)	$	117,448

The accompanying notes are an integral part of these unaudited 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, 2017

(in Thousands, except unit amounts)



				Limited Partners
				Class B Preferred			Common					Accumulated Other
	General Partner			Units	Amount		Units		Amount			Comprehensive Loss			Noncontrolling Interests			Total Equity
BALANCES AT MARCH 31, 2017	$	(50,529	)	—	$	—	120,179,407		$	2,192,413		$	(1,828	)	$	26,746		$	2,166,802
Distributions to general and common unit partners and preferred unitholders (Note 10)	(242		)	—	—		—		(171,072		)	—			—			(171,314		)
Distributions to noncontrolling interest owners	—			—	—		—		—			—			(3,082		)	(3,082		)
Contributions	—			—	—		—		—			—			23			23
Purchase of noncontrolling interest (Note 4)	—			—	—		—		(6,245		)	—			(16,638		)	(22,883		)
Redemption valuation adjustment (Note 2)	—			—	—		—		(1,201		)	—			—			(1,201		)
Repurchase of warrants (Note 10)	—			—	—		—		(10,549		)	—			—			(10,549		)
Equity issued pursuant to incentive compensation plan (Note 10)	23			—	—		1,855,102		28,611			—			—			28,634
Common unit repurchases and cancellations (Note 10)	—			—	—		(1,558,498	)	(15,608		)	—			—			(15,608		)
Warrants exercised (Note 10)	—			—	—		607,653		6			—			—			6
Accretion of beneficial conversion feature of Class A convertible preferred units (Note 10)	—			—	—		—		(12,259		)	—			—			(12,259		)
Issuance of Class B preferred units (Note 10)	—			8,400,000	202,731		—		—			—			—			202,731
Net (loss) income	(121		)	—	—		—		(180,356		)	—			221			(180,256		)
Other comprehensive income	—			—	—		—		—			350			—			350
BALANCES AT DECEMBER 31, 2017	$	(50,869	)	8,400,000	$	202,731	121,083,664		$	1,823,740		$	(1,478	)	$	7,270		$	1,981,394

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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Cash Flows

(in Thousands)



	Nine Months Ended December 31,
	2017			2016
OPERATING ACTIVITIES:
Net (loss) income	$	(180,517	)	$	117,388
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depreciation and amortization, including amortization of debt issuance costs	205,192			173,566
Loss (gain) on early extinguishment or revaluation of liabilities, net	28,079			(30,890		)
Gain on termination of a storage sublease agreement	—			(16,205		)
Non-cash equity-based compensation expense	27,114			39,859
Gain on disposal or impairment of assets, net	(11,242		)	(203,433		)
Provision for doubtful accounts	1,910			471
Net adjustments to fair value of commodity derivatives	99,814			102,638
Equity in earnings of unconsolidated entities	(7,270		)	(1,726		)
Distributions of earnings from unconsolidated entities	4,891			2,094
Revaluation of investments	—			14,365
Other	854			(3,269		)
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable-trade and affiliates	(278,547		)	(245,065		)
Inventories	(90,037		)	(244,941		)
Other current and noncurrent assets	(11,534		)	(65,331		)
Accounts payable-trade and affiliates	200,363			245,506
Other current and noncurrent liabilities	14,991			(599		)
Net cash provided by (used in) operating activities	4,061			(115,572		)
INVESTING ACTIVITIES:
Capital expenditures	(99,384		)	(264,580		)
Acquisitions, net of cash acquired	(49,481		)	(127,513		)
Cash flows from settlements of commodity derivatives	(85,823		)	(82,815		)
Proceeds from sales of assets	33,673			14,195
Proceeds from sale of interest in Glass Mountain	292,117			—
Proceeds from sale of TLP common units	—			112,370
Proceeds from sale of Grassland	—			22,000
Transaction with an unconsolidated entity (Note 13)	(6,424		)	—
Investments in unconsolidated entities	(21,461		)	—
Distributions of capital from unconsolidated entities	11,710			7,608
Repayments on loan for natural gas liquids facility	7,425			6,585
Loan to affiliate	(1,460		)	(2,700		)
Repayments on loan to affiliate	4,160			655
Payment to terminate development agreement	—			(16,875		)
Other (Note 14)	20,000			—
Net cash provided by (used in) investing activities	105,052			(331,070		)
FINANCING ACTIVITIES:
Proceeds from borrowings under Revolving Credit Facility	1,674,500			1,176,000
Payments on Revolving Credit Facility	(1,349,500		)	(1,510,500		)
Issuance of senior unsecured notes	—			700,000
Repayment and repurchase of senior secured and senior unsecured notes	(415,568		)	(15,129		)
Payments on other long-term debt	(4,361		)	(6,549		)
Debt issuance costs	(2,497		)	(12,608		)
Contributions from general partner	—			59
Contributions from noncontrolling interest owners, net	23			639
Distributions to general and common unit partners and preferred unitholders	(166,589		)	(132,135		)
Distributions to noncontrolling interest owners	(3,082		)	(3,292		)
Proceeds from sale of preferred units, net of offering costs	202,731			234,989
Repurchase of warrants	(10,549		)	—
Common unit repurchases and cancellations	(15,608		)	—
Proceeds from sale of common units, net of offering costs	—			43,896
Payments for settlement and early extinguishment of liabilities	(2,408		)	(27,977		)
Net cash (used in) provided by financing activities	(92,908		)	447,393
Net increase in cash and cash equivalents	16,205			751
Cash and cash equivalents, beginning of period	12,264			28,176
Cash and cash equivalents, end of period	$	28,469		$	28,927
Supplemental cash flow information:
Cash interest paid	$	153,788		$	89,102
Income taxes paid (net of income tax refunds)	$	1,614		$	1,985
Supplemental non-cash investing and financing activities:
Distributions declared but not paid to Class B preferred unitholders	$	4,725		$	—
Accrued capital expenditures	$	7,444		$	2,754
Value of common units issued in business combinations	$	—		$	3,947

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

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements

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, 2017, our operations include:


•	Our Crude Oil Logistics segment purchases crude oil from producers and transports it to refineries or for resale at pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs, and provides terminaling, trucking, marine and pipeline transportation services through its owned assets.


•	Our Water Solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production and for the disposal of solids such as tank bottoms and drilling fluids and performs truck and frac tank washouts. In addition, our Water Solutions segment sells the recovered hydrocarbons that result from performing these services.


•	Our Liquids segment supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada using its leased underground storage and fleet of leased railcars, markets regionally through its 21 owned terminals throughout the United States, and provides terminaling and storage services at its salt dome storage facility in Utah.


•	Our Retail Propane segment sells propane, distillates, equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 30 states and the District of Columbia.


•	Our Refined Products and Renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations, purchases refined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedules them for delivery at various locations throughout the country.

Note 2—Significant Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include our accounts and those of our controlled subsidiaries. Intercompany transactions and account balances have been eliminated in consolidation. Investments we cannot control, but can exercise significant influence over, are accounted for using the equity method of accounting. We also own an undivided interest in a crude oil pipeline, and include our proportionate share of assets, liabilities, and expenses related to this pipeline in our unaudited condensed consolidated financial statements.

Our unaudited condensed consolidated financial statements are 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 (“SEC”). Accordingly, the unaudited condensed consolidated financial statements exclude certain 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. 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 only of normal recurring items, unless otherwise disclosed in this Quarterly Report. The unaudited condensed consolidated balance sheet at March 31, 2017 was derived from our audited consolidated financial statements for the fiscal year ended March 31, 2017 included in our Annual Report on Form 10-K (“Annual Report”) filed with the SEC on May 26, 2017.

These interim unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report. Due to the seasonal nature of certain of our operations and other factors, the results of operations for interim periods are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2018.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the amount of assets and liabilities reported at the date of the consolidated financial statements and the amount of revenues and expenses reported during the periods presented.

Critical estimates we make in the preparation of our unaudited condensed consolidated financial statements include, among others, determining the fair value of assets and liabilities acquired in business combinations, the collectibility of accounts receivable, the recoverability of inventories, useful lives and recoverability of property, plant and equipment and amortizable intangible assets, the impairment of long-lived assets and goodwill, the fair value of asset retirement obligations, the value of equity-based compensation, and accruals for environmental matters. Although we believe these estimates are reasonable, 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.

Fair Value Measurements

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


•	Level 1: Quoted prices 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 (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability, and (iv) 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 forward commodity contracts. We determine the fair value of all of our derivative financial instruments utilizing pricing models for similar instruments. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.


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

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable inputs (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 a fair value measurement requires judgment, considering factors specific to the asset or liability.

Derivative Financial Instruments

We record all derivative financial instrument contracts at fair value in our unaudited condensed consolidated balance sheets except for certain contracts that qualify for the normal purchase and normal sale election. 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.

We have not designated any financial instruments as hedges for accounting purposes. All changes in the fair value of our commodity derivative instruments that do not qualify as normal purchases and normal sales (whether cash transactions or

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

non-cash mark-to-market adjustments) are reported within cost of sales in our unaudited condensed consolidated statements of operations, regardless of whether the contract is physically or financially settled.

We utilize various commodity derivative financial instrument contracts to attempt to reduce our exposure to price fluctuations. We do not enter into such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in market prices, newly originated transactions, and the timing of settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipated market movements. Inherent in the resulting contractual portfolio are 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, or refined and renewables 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. Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions.

Revenue Recognition

We record product sales revenues when title to the product transfers to the purchaser, which typically occurs when the purchaser receives the product. We record terminaling, transportation, storage, and service revenues when the service is performed, and we record tank and other rental revenues over the lease term. Revenues for our Water Solutions segment are recognized when we obtain the wastewater at our treatment and disposal facilities.

The tariffs we charge for our pipeline transportation systems are primarily regulated by the Federal Energy Regulatory Commission. Our tariffs include provisions which allow us to deduct from our customer’s inventory a small percentage of the products our customers transport on our pipeline systems. We refer to these product quantities as pipeline loss allowance. We receive pipeline loss allowances from our customers as consideration for product losses during the transportation of their products on our pipeline systems. Our customers are guaranteed delivery of the amount of their injected volumes, net of pipeline loss allowance, irrespective of what our actual product losses may be during the delivery process.

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. We include amounts billed to customers for shipping and handling costs in revenues in our unaudited 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 at the same time and in contemplation of each other, we record the revenues for these transactions net of cost of sales.

Revenues during the three months ended December 31, 2017 and 2016 include $0.3 million and $1.2 million, respectively, and revenues during the nine months ended December 31, 2017 and 2016 include $1.0 million and $3.7 million, respectively, associated with the amortization of a liability recorded in the acquisition accounting for an acquired business related to certain out-of-market revenue contracts.

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 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 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

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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 our unaudited condensed consolidated financial statements at December 31, 2017 or March 31, 2017.

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the “Act”) was signed into law by the President of the United States. The Act amended the Internal Revenue Code of 1986 for taxable years beginning after December 31, 2017 and does not extend retroactively to any prior tax periods. Beginning in tax year 2018, the deductibility of net interest expense is limited to 30% of our adjusted taxable income. For tax years beginning after December 31, 2017 and before January 1, 2022, the Act calculates adjusted taxable income using an EBITDA-based calculation. For tax years beginning January 1, 2022 and thereafter, the calculation of adjusted taxable income will not add back depreciation or amortization. Any disallowed business interest expense is then generally carried forward as a deduction in a succeeding taxable year at the partner level. These limitations might cause interest expense to be deducted by our unitholders in a later period than recognized in the GAAP financial statements.

As of December 31, 2017, we do not have any deferred tax assets or liabilities. Any future deferred tax assets or liabilities will be valued based on the new corporate tax rate under the Act.

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 reporting period. On April 1, 2017, we adopted the new inventory standard, Accounting Standards Update (“ASU”) No. 2015-11. Under this ASU, inventory is to be measured at the lower of cost or net realizable value, which is defined as the estimated selling price in the ordinary course of business, less reasonable predictable costs of completion, disposal, and transportation. In performing this analysis, we consider fixed-price forward commitments and the opportunity to transfer propane inventory from our wholesale Liquids business to our Retail Propane business to sell the inventory in retail markets.

Inventories consist of the following at the dates indicated:



	December 31, 2017		March 31, 2017
	(in thousands)
Crude oil	$	77,306	$	146,857
Natural gas liquids:
Propane	118,998		38,631
Butane	40,670		5,992
Other	11,778		6,035
Refined products:
Gasoline	214,717		193,051
Diesel	129,126		98,237
Renewables:
Ethanol	39,631		42,009
Biodiesel	8,124		21,410
Other	4,750		9,210
Total	$	645,100	$	561,432

Amounts as of December 31, 2017 in the table above exclude inventory related to the potential sale of a portion of the Retail Propane segment, as these amounts have been classified as current assets held for sale in our unaudited condensed consolidated balance sheet (see Note 14).

Investments in Unconsolidated Entities

Investments we cannot control, but can exercise significant influence over, are accounted for using the equity method of accounting. Investments in partnerships and limited liability companies, unless our investment is considered to be minor, and

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

investments in unincorporated joint ventures are also accounted for using the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on our unaudited condensed consolidated balance sheets; instead, our ownership interests are reported within investments in unconsolidated entities on our unaudited 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. We use the cumulative earnings approach to classify distributions received from unconsolidated entities as either operating activities or investing activities in our unaudited condensed consolidated statements of cash flows.

Our investments in unconsolidated entities consist of the following at the dates indicated:



Entity	Segment	Ownership Interest (1)	Date Acquired or Formed	December 31, 2017		March 31, 2017
				(in thousands)
Glass Mountain Pipeline, LLC (2)	Crude Oil Logistics	—%	December 2013	$	—	$	172,098
E Energy Adams, LLC	Refined Products and Renewables	19%	December 2013	14,369		12,952
Water treatment and disposal facility (3)	Water Solutions	50%	August 2015	2,000		2,147
Victory Propane, LLC (4)	Retail Propane	50%	April 2015	—		226
Total				$	16,369	$	187,423


(1)	Ownership interest percentages are at December 31, 2017.


(2)	On December 22, 2017, we sold our previously held 50% interest in Glass Mountain Pipeline, LLC for net proceeds of $292.1 million and recorded a gain on disposal of $108.6 million during the three months ended December 31, 2017 within (gain) loss on disposal or impairment of assets, net in our unaudited condensed consolidated statement of operations.


(3)	This is an investment in an unincorporated joint venture.


(4)	As our investment is $0 at December 31, 2017, our proportionate share of Victory Propane, LLC’s (“Victory Propane”) losses have been recorded against the loan receivable we have with Victory Propane. See Note 13 for a further discussion of the loan receivable and a description of other transactions between us and Victory Propane.

Variable Interest Entity

Victory Propane was formed as a joint venture in April 2015 by us and an unrelated third party. The business purpose of Victory Propane is to acquire and/or develop retail propane operations in a defined geographic area. In conjunction with the formation of Victory Propane, we agreed to provide Victory Propane a revolving line of credit of $5.0 million to be used for working capital and/or acquisition funding. Victory Propane began using this revolving line of credit shortly after operations commenced. At December 31, 2017, we provided a majority of Victory Propane’s financing and have concluded that Victory Propane is a variable interest entity because the equity is not sufficient to fund Victory Propane’s activities without additional subordinated financial support. Each joint venture member has an equal ownership interest in Victory Propane and has equal representation on Victory Propane’s board of managers to make all significant decisions relating to the operations of Victory Propane. Therefore, we do not have the power to direct activities that significantly influence the economic performance of Victory Propane and have concluded that we are not the primary beneficiary. Our maximum exposure to loss related to Victory Propane is limited to the sum of our equity investment as shown in the table above and the outstanding loan receivable (see Note 13) at December 31, 2017.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Other Noncurrent Assets

Other noncurrent assets consist of the following at the dates indicated:



	December 31, 2017		March 31, 2017
	(in thousands)
Loan receivable (1)	$	32,396	$	40,684
Line fill (2)	36,446		30,628
Tank bottoms (3)	42,044		42,044
Minimum shipping fees - pipeline commitments (4)	82,301		67,996
Other	49,578		58,252
Total	$	242,765	$	239,604


(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 on certain third-party owned pipelines under long-term shipment commitments. At December 31, 2017, line fill consisted of 377,320 barrels of crude oil and 262,000 barrels of propane (requirement is due to a new contract). At March 31, 2017, line fill consisted of 427,193 barrels of crude oil. Line fill held in pipelines we own is included within property, plant and equipment (see Note 5).

(3)

Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms when the storage tanks are removed from service. At December 31, 2017 and March 31, 2017, tank bottoms held in third party terminals consisted of 366,212 barrels and 366,212 barrels of refined products, respectively. Tank bottoms held in terminals we own are included within property, plant and equipment (see Note 5).


(4)	Represents the minimum shipping fees paid in excess of volumes shipped for two contracts. This amount can be recovered when volumes shipped exceed the minimum monthly volume commitment (see Note 9). Under these contracts, we currently have 2.3 years and 2.8 years, respectively, in which to ship the excess volumes.

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following at the dates indicated:



	December 31, 2017		March 31, 2017
	(in thousands)
Accrued compensation and benefits	$	16,237	$	22,227
Excise and other tax liabilities	48,803		64,051
Derivative liabilities	34,713		27,622
Accrued interest	33,389		44,418
Product exchange liabilities	24,312		1,693
Deferred gain on sale of general partner interest in TLP	30,113		30,113
Other	43,185		17,001
Total	$	230,752	$	207,125

Amounts as of December 31, 2017 in the table above exclude accrued expenses and other payables related to the potential sale of a portion of the Retail Propane segment, as these amounts have been classified as current liabilities held for sale in our unaudited condensed consolidated balance sheet (see Note 14).

Deferred Gain on Sale of General Partner Interest in TLP

On February 1, 2016, we sold our general partner interest in TransMontaigne Partners L.P. (“TLP”) to an affiliate of ArcLight Capital Partners. We deferred a portion of the gain on the sale and will recognize this amount over our future lease payment obligations, which is approximately seven years. During the three months ended December 31, 2017 and 2016, we recognized $7.5 million and $7.5 million, respectively, and during the nine months ended December 31, 2017 and 2016, we recognized $22.6 million and $22.6 million, respectively, of the deferred gain in our unaudited condensed consolidated

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

statements of operations. Within our December 31, 2017 unaudited condensed consolidated balance sheet, the current portion of the deferred gain, $30.1 million, is recorded in accrued expenses and other payables, and the long-term portion, $116.7 million, is recorded in other noncurrent liabilities.

Noncontrolling Interests

Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. Amounts are adjusted by the noncontrolling interest holder’s proportionate share of the subsidiaries’ earnings or losses each period and any distributions that are paid. Noncontrolling interests are reported as a component of equity, unless the noncontrolling interest is considered redeemable, in which case the noncontrolling interest is recorded between liabilities and equity (mezzanine or temporary equity) in our unaudited condensed consolidated balance sheet. The redeemable noncontrolling interest is adjusted at each balance sheet date to its maximum redemption value if the amount is greater than the carrying value. During the nine months ended December 31, 2017, we recorded $1.2 million to adjust the redeemable noncontrolling interest to its maximum redemption value.

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 discussed 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 discussed in Note 4, we made certain adjustments during the nine months ended December 31, 2017 to our estimates of the acquisition date fair values of assets acquired and liabilities assumed in business combinations that occurred during the fiscal year ended March 31, 2017.

Reclassifications

We have reclassified certain prior period financial statement information to be consistent with the classification methods used in the current fiscal year. These reclassifications did not impact previously reported amounts of equity, net income, or cash flows.

Recent Accounting Pronouncements

In August 2016, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2016-15, “Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments.” The ASU requires cash payments not made soon after the acquisition date of a business combination by an acquirer to settle a contingent consideration liability to be separated and classified as cash outflows for financing activities and operating activities. Cash payments up to the amount of the contingent consideration liability recognized at the acquisition date (including measurement-period adjustments) should be classified as financing activities and any excess should be classified as operating activities. We adopted this ASU effective April 1, 2017 and have revised previously reported information.

In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments-Credit Losses.” The ASU requires a financial asset (or a group of financial assets) measured at amortized cost to be presented at the net amount expected to be collected, which would include accounts receivable. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectibility of the reported amount. The ASU is effective for the Partnership beginning April 1, 2020, and requires a modified retrospective method of adoption, although early adoption is permitted. We are currently in the process of assessing the impact of this ASU on our consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016-02, “Leases.” The ASU will replace previous lease accounting guidance in GAAP. The ASU requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The ASU retains a distinction between finance leases and operating leases. The ASU is effective for the Partnership beginning April 1, 2019, and requires a modified retrospective method of adoption. We are currently in the process

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

of compiling a database of leases and analyzing each lease to assess the impact under this ASU on our consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The ASU 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, 2018, and allows for both full retrospective and modified retrospective methods of adoption.

We are in the process of evaluating our revenue contracts by segment and type to determine the potential impact of adopting this ASU. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts, particularly contracts with minimum volume commitments, specifically in our Water Solutions, Crude Oil Logistics, Refined and Renewables and Liquids segments, tiered pricing, non-cash consideration and multi-year services arrangements, may be impacted by the adoption of this ASU; however, we are still in the process of quantifying these impacts, if any, and have not yet determined whether they would be material to our consolidated financial statements. We have hired a third-party to assist us in the evaluation of these contracts. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support recognition and disclosure under this ASU. We continue to monitor additional authoritative or interpretive guidance related to this ASU as it becomes available, as well as comparing our conclusions on specific interpretative issues to other peers in our industry, to the extent that such information is available to us. We currently anticipate utilizing a modified retrospective adoption as of April 1, 2018.

Note 3—Income (Loss) Per Common Unit

The following table presents our calculation of basic and diluted weighted average units outstanding for the periods indicated:



	Three Months Ended December 31,		Nine Months Ended December 31,
	2017	2016	2017	2016
Weighted average units outstanding during the period:
Common units - Basic	120,844,008	107,966,901	120,899,502	106,114,668
Effect of Dilutive Securities:
Performance awards	—	—	—	111,826
Warrants	2,914,383	—	—	3,328,434
Service awards	403,575	—	—	—
Common units - Diluted	124,161,966	107,966,901	120,899,502	109,554,928

For the three months ended December 31, 2017, the Class A Preferred Units (as defined herein) and Performance Awards (as defined herein) were considered antidilutive. For the nine months ended December 31, 2017 and three months ended December 31, 2016, the Class A Preferred Units, Performance Awards, Service Awards and warrants were considered antidilutive. For the nine months ended December 31, 2016, the Class A Preferred Units and Service Awards were considered antidilutive.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Our income (loss) per common unit is as follows for the periods indicated:



	Three Months Ended December 31,						Nine Months Ended December 31,
	2017			2016			2017			2016
	(in thousands, except unit and per unit amounts)
Net income (loss)	$	56,769		$	1,293		$	(180,517	)	$	117,388
Less: Net income attributable to noncontrolling interests	(89		)	(317		)	(221		)	(6,091		)
Less: Net (income) loss attributable to redeemable noncontrolling interests	(424		)	—			261			—
Net income (loss) attributable to NGL Energy Partners LP	56,256			976			(180,477		)	111,297
Less: Distributions to preferred unitholders	(16,219		)	(8,906		)	(42,001		)	(20,958		)
Less: Net (income) loss allocated to general partner (1)	(73		)	(22		)	121			(180		)
Less: Repurchase of warrants (2)	—			—			(349		)	—
Net income (loss) allocated to common unitholders	$	39,964		$	(7,952	)	$	(222,706	)	$	90,159
Basic income (loss) per common unit	$	0.33		$	(0.07	)	$	(1.84	)	$	0.85
Diluted income (loss) per common unit	$	0.32		$	(0.07	)	$	(1.84	)	$	0.82
Basic weighted average common units outstanding	120,844,008			107,966,901			120,899,502			106,114,668
Diluted weighted average common units outstanding	124,161,966			107,966,901			120,899,502			109,554,928


(1)	Net (income) loss allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights.


(2)	This amount represents the excess of the repurchase price over the fair value of the warrants, as discussed further in Note 10.

Note 4—Acquisitions

The following summarizes our acquisitions during the nine months ended December 31, 2017:

Acquisition of Remaining Interest in NGL Solids Solutions, LLC

On April 17, 2017, we entered into a purchase and sale agreement with the party owning the 50% noncontrolling interest in NGL Solids Solutions, LLC, a consolidated subsidiary in our Water Solutions segment. Total consideration was $23.1 million, which consisted of cash of $20.0 million and the termination of a non-compete agreement that we valued at $3.1 million, and in return we received the following:


•	The remaining 50% interest in NGL Solids Solutions, LLC; and


•	Two parcels of land to develop saltwater disposal wells.

We accounted for the transaction as an acquisition of assets. Acquiring assets in groups requires not only ascertaining the cost of the asset (or net asset) group but also allocating that cost to the individual assets (or individual assets and liabilities) that make up the group. The cost of a group of assets acquired in an asset acquisition is allocated to the individual assets acquired or liabilities assumed/released based on their relative fair values and does not give rise to goodwill or bargain purchase gains. We allocated $22.9 million to noncontrolling interest and $0.2 million to land. The acquisition of the remaining interest was accounted for as an equity transaction, no gain or loss was recorded and the carrying value of the noncontrolling interest was adjusted to reflect the change in ownership interest of the subsidiary. As of the date of the transaction, the 50% noncontrolling interest had a carrying value of $16.6 million. For the termination of the non-compete agreement, we recorded a gain of $1.3 million, which included the carrying value of the non-compete agreement intangible asset that was written off (see Note 7). This gain was recorded within (gain) loss on disposal or impairment of assets, net in our unaudited condensed consolidated statement of operations during the nine months ended December 31, 2017.

Retail Propane Businesses

During the nine months ended December 31, 2017, we acquired six retail propane businesses for total consideration of $30.5 million. The agreements for these acquisitions contemplate post-closing payments for certain working capital items.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed for these retail propane businesses, and as a result, the estimates of fair value at December 31, 2017 are subject to change. The following table summarizes the preliminary estimates of the fair values of the assets acquired and liabilities assumed (in thousands):



Current assets	$	2,042
Property, plant and equipment	10,686
Goodwill	3,010
Intangible assets	16,625
Current liabilities	(1,586		)
Other noncurrent liabilities	(291		)
Fair value of net assets acquired	$	30,486

Goodwill represents the excess of the consideration paid for the acquired businesses over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill represents a premium paid to acquire the skilled workforce of each of the businesses acquired and the ability to expand into new markets. We expect that all of the goodwill will be deductible for federal income tax purposes.

The operations of these retail propane businesses have been included in our unaudited condensed consolidated statement of operations since their acquisition date. Our unaudited condensed consolidated statement of operations for the nine months ended December 31, 2017 includes revenues of $8.8 million and operating income of $0.8 million that were generated by the operations of three of these retail propane businesses. The revenues and operating income of the other retail propane business acquisitions are not considered material.

The following summarizes the status of the preliminary purchase price allocation of acquisitions prior to April 1, 2017:

Water Solutions Facilities

During the six months ended September 30, 2017, we completed the acquisition accounting for two water solutions facilities. During the six months ended September 30, 2017, we received additional information and recorded a decrease of $0.2 million to property, plant and equipment and an increase of less than $0.1 million to other noncurrent liabilities related to an asset retirement obligation. The offset of these adjustments was recorded to goodwill.

Retail Propane Businesses

During the nine months ended December 31, 2017, we completed the acquisition accounting for four retail propane businesses. During the nine months ended December 31, 2017, we received additional information and recorded a decrease of $0.2 million to current assets and a decrease of less than $0.1 million to property, plant and equipment. The offset of these adjustments was recorded to goodwill. In addition, we paid $0.4 million in cash to the sellers during the nine months ended December 31, 2017 for consideration that was held back at the acquisition date, which we recorded as a liability within accrued expenses and other payables in our unaudited condensed consolidated balance sheet.

Natural Gas Liquids Facilities

During the three months ended June 30, 2017, we completed the acquisition accounting for certain natural gas liquids facilities acquired in January 2017. There were no material adjustments to the fair value of assets acquired and liabilities assumed during the three months ended June 30, 2017.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Note 5—Property, Plant and Equipment

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



Description	Estimated Useful Lives	December 31, 2017			March 31, 2017
		(in thousands)
Natural gas liquids terminal and storage assets	2–30 years	$	238,092		$	207,825
Pipeline and related facilities	30–40 years	255,930			248,582
Refined products terminal assets and equipment	15–25 years	7,062			6,736
Retail propane equipment	2–30 years	195,414			239,417
Vehicles and railcars	3–25 years	179,691			198,480
Water treatment facilities and equipment	3–30 years	585,569			557,100
Crude oil tanks and related equipment	2–30 years	218,056			203,003
Barges and towboats	5–30 years	91,884			91,037
Information technology equipment	3–7 years	43,495			43,880
Buildings and leasehold improvements	3–40 years	167,446			161,957
Land		56,593			56,545
Tank bottoms and line fill (1)		20,094			24,462
Other	3–20 years	14,802			39,132
Construction in progress		54,729			87,711
		2,128,857			2,165,867
Accumulated depreciation		(420,174		)	(375,594		)
Net property, plant and equipment		$	1,708,683		$	1,790,273


(1)	Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms when the storage tanks are removed from service. Line fill, which represents our portion of the product volume required for the operation of the proportionate share of a pipeline we own, is recorded at historical cost.

Amounts as of December 31, 2017 in the table above exclude property, plant and equipment and the accumulated depreciation related to the potential sale of a portion of the Retail Propane segment, as these amounts have been classified as current assets held for sale in our unaudited condensed consolidated balance sheet (see Note 14).

The following table summarizes depreciation expense and capitalized interest expense for the periods indicated:



	Three Months Ended December 31,				Nine Months Ended December 31,
	2017		2016		2017		2016
	(in thousands)
Depreciation expense	$	32,629	$	32,039	$	98,761	$	88,396
Capitalized interest expense	$	66	$	1,429	$	66	$	6,233

We record losses (gains) from the sales of property, plant and equipment and any write-downs in value due to impairment within (gain) loss on disposal or impairment of assets, net in our unaudited condensed consolidated statements of operations. During the three months ended December 31, 2017, we recorded a net loss of $4.7 million. The net loss consisted of losses of $7.5 million related to the disposal of certain assets, offset by a gain of $2.8 million related to the sale of excess pipe in our Crude Oil Logistics segment. During the nine months ended December 31, 2017, we recorded a net loss of $4.0 million. The net loss consisted of losses of $10.6 million related to the disposal of certain assets and the write-down of other assets, offset by a gain of $6.6 million related to the sale of excess pipe in our Crude Oil Logistics segment.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Note 6—Goodwill

The following table summarizes changes in goodwill by segment during the nine months ended December 31, 2017:



	Crude Oil Logistics		Water Solutions		Liquids			Retail Propane			Refined Products and Renewables		Total
	(in thousands)
Balances at March 31, 2017	$	579,846	$	424,270	$	266,046		$	130,427		$	51,127	$	1,451,716
Revisions to acquisition accounting (Note 4)	—		195		—			232			—		427
Acquisitions (Note 4)	—		—		—			3,010			—		3,010
Impairment	—		—		(116,877		)	—			—		(116,877		)
Assets held for sale (Note 14)	—		—		—			(24,959		)	—		(24,959		)
Balances at December 31, 2017	$	579,846	$	424,465	$	149,169		$	108,710		$	51,127	$	1,313,317

Goodwill Impairment

Due to the decreased demand for natural gas liquid storage and resulting decline in revenues and earnings as compared to actual and projected results of prior and future periods, we tested the goodwill within our natural gas liquids salt cavern storage reporting unit (“Sawtooth reporting unit”), which is part of our Liquids segment, for impairment at September 30, 2017. We estimated the fair value of our Sawtooth reporting unit based on the income approach, also known as the discounted cash flow method, which utilizes the present value of future expected cash flows to estimate the fair value. The future cash flows of our Sawtooth reporting unit were projected based upon estimates as of the test date of future revenues, operating expenses and cash outflows necessary to support these cash flows, including working capital and maintenance capital expenditures. We also considered expectations regarding: (i) expected storage volumes, which are assumed to increase in the coming years due to increased production of natural gas liquids, (ii) expected propane and butane prices and (iii) expected rental fees. We assumed a 2% per year increase in commodity prices and a 4% increase in rental fees per year starting in April 2018, and held such prices and fees flat for periods in our model beyond our 2023 fiscal year. For expenses, we assumed an increase consistent with the increase in storage volumes, and maintenance capital was held flat throughout the model. The discount rate used in our discounted cash flow method was a risk adjusted weighted average cost of capital calculated as of September 30, 2017 of 12%. The discounted cash flow results indicated that the estimated fair value of our Sawtooth reporting unit was less than its carrying value by approximately 32% at September 30, 2017.

During the three months ended September 30, 2017, we recorded a goodwill impairment charge of $116.9 million, which was recorded within (gain) loss on disposal or impairment of assets, net, in our unaudited condensed consolidated statement of operations. At September 30, 2017, our Sawtooth reporting unit had a goodwill balance of $66.2 million.

Our estimated fair value is predicated upon management’s assumption of the growth in the production of natural gas liquids and the decline in the use of railcars to store natural gas liquids. We used these assumptions to estimate the demand for storage at our facility and the revenue generated by customers reserving capacity at our facility. Due to the current volatility in commodity prices and the excess railcars currently in the market, we believe it is reasonably possible that the need for underground storage we estimate in our model does not materialize, such that our estimate of fair value could change and result in further impairment of the goodwill in our Sawtooth reporting unit.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Note 7—Intangible Assets

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



		December 31, 2017							March 31, 2017
Description	Amortizable Lives	Gross Carrying Amount		Accumulated Amortization			Net		Gross Carrying Amount		Accumulated Amortization			Net
		(in thousands)
Amortizable:
Customer relationships	3–20 years	$	882,256	$	(352,364	)	$	529,892	$	906,782	$	(316,242	)	$	590,540
Customer commitments	10 years	310,000		(36,167		)	273,833		310,000		(12,917		)	297,083
Pipeline capacity rights	30 years	161,785		(15,697		)	146,088		161,785		(11,652		)	150,133
Rights-of-way and easements	1–40 years	63,485		(2,670		)	60,815		63,402		(2,154		)	61,248
Executory contracts and other agreements	3–30 years	23,097		(16,626		)	6,471		29,036		(20,457		)	8,579
Non-compete agreements	2–32 years	17,988		(6,767		)	11,221		32,984		(17,762		)	15,222
Trade names	1–10 years	4,076		(1,822		)	2,254		15,439		(13,396		)	2,043
Debt issuance costs (1)	5 years	40,790		(23,419		)	17,371		38,983		(20,025		)	18,958
Total amortizable		1,503,477		(455,532		)	1,047,945		1,558,411		(414,605		)	1,143,806
Non-amortizable:
Trade names		17,010		—			17,010		20,150		—			20,150
Total non-amortizable		17,010		—			17,010		20,150		—			20,150
Total		$	1,520,487	$	(455,532	)	$	1,064,955	$	1,578,561	$	(414,605	)	$	1,163,956


(1)	Includes debt issuance costs related to the Revolving Credit Facility (as defined herein). Debt issuance costs related to fixed-rate notes are reported as a reduction of the carrying amount of long-term debt.

Amounts as of December 31, 2017 in the table above exclude intangible assets and the accumulated amortization related to the potential sale of a portion of the Retail Propane segment, as these amounts have been classified as current assets held for sale in our unaudited condensed consolidated balance sheet (see Note 14).

The weighted-average remaining amortization period for intangible assets is approximately 11.4 years.

Write off of Intangible Asset

During the nine months ended December 31, 2017, we wrote off $1.8 million related to the non-compete agreement which was terminated as part of our acquisition of the remaining interest in NGL Solids Solutions, LLC (see Note 4).

Amortization expense is as follows for the periods indicated:



	Three Months Ended December 31,				Nine Months Ended December 31,
Recorded In	2017		2016		2017		2016
	(in thousands)
Depreciation and amortization	$	30,711	$	28,728	$	93,666	$	71,880
Cost of sales	1,505		1,753		4,596		5,098
Interest expense	1,154		1,721		3,394		5,177
Total	$	33,370	$	32,202	$	101,656	$	82,155

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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



Fiscal Year Ending March 31,
2018 (three months)	$	32,936
2019	128,009
2020	124,632
2021	111,519
2022	96,432
Thereafter	554,417
Total	$	1,047,945

Note 8—Long-Term Debt

Our long-term debt consists of the following at the dates indicated:



	December 31, 2017							March 31, 2017
	Face Amount		Unamortized Debt Issuance Costs (1)			Book Value		Face Amount		Unamortized Debt Issuance Costs (1)			Book Value
	(in thousands)
Revolving credit facility:
Expansion capital borrowings	$	125,000	$	—		$	125,000	$	—	$	—		$	—
Working capital borrowings	1,014,500		—			1,014,500		814,500		—			814,500
Senior secured notes	—		—			—		250,000		(4,559		)	245,441
Senior unsecured notes:
5.125% Notes due 2019	360,781		(2,015		)	358,766		379,458		(3,191		)	376,267
6.875% Notes due 2021	367,048		(4,817		)	362,231		367,048		(5,812		)	361,236
7.500% Notes due 2023	656,589		(9,515		)	647,074		700,000		(11,329		)	688,671
6.125% Notes due 2025	412,507		(6,536		)	405,971		500,000		(8,567		)	491,433
Other long-term debt	11,684		—			11,684		15,525		—			15,525
	2,948,109		(22,883		)	2,925,226		3,026,531		(33,458		)	2,993,073
Less: Current maturities	3,260		—			3,260		29,590		—			29,590
Long-term debt	$	2,944,849	$	(22,883	)	$	2,921,966	$	2,996,941	$	(33,458	)	$	2,963,483


(1)	Debt issuance costs related to the Revolving Credit Facility are reported within intangible assets, rather than as a reduction of the carrying amount of long-term debt.

Amortization expense for debt issuance costs related to long-term debt in the table above was $1.5 million and $1.2 million during the three months ended December 31, 2017 and 2016, respectively, and $4.8 million and $3.0 million during the nine months ended December 31, 2017 and 2016, respectively.

Expected amortization of debt issuance costs is as follows (in thousands):



Fiscal Year Ending March 31,
2018 (three months)	$	1,283
2019	5,124
2020	4,191
2021	3,810
2022	3,229
Thereafter	5,246
Total	$	22,883

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Credit Agreement

We are party to a $1.765 billion credit agreement (the “Credit Agreement”) with a syndicate of banks. As of December 31, 2017, the Credit Agreement includes a revolving credit facility to fund working capital needs, which had a capacity of $1.2 billion for cash borrowings and letters of credit, (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects, which had a capacity of $565.0 million (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). During the three months ended September 30, 2017, we reallocated $50.0 million from the Expansion Capital Facility to the Working Capital Facility. During the three months ended December 31, 2017, we reallocated an additional $150.0 million from the Expansion Capital Facility to the Working Capital Facility. We had letters of credit of $182.1 million on the Working Capital Facility at December 31, 2017.

At December 31, 2017, the borrowings under the Credit Agreement had a weighted average interest rate of 4.90%, calculated as the weighted average LIBOR rate of 1.53% plus a margin of 3.00% for LIBOR borrowings and the prime rate of 4.50% plus a margin of 2.00% on alternate base rate borrowings. At December 31, 2017, the interest rate in effect on letters of credit was 3.00%. Commitment fees were charged at a rate ranging from 0.375% to 0.50% on any unused capacity.

On June 2, 2017, we amended our Credit Agreement. The amendment, among other things, restricts us from increasing our distribution rate over the amount paid in the preceding quarter if our leverage ratio is greater than 4.25 to 1. In addition, the Credit Agreement contains covenants that require us to satisfy certain debt ratios, which are summarized in the table below.



		Senior Secured	Interest
Period Beginning	Leverage Ratio (1)	Leverage Ratio (1)	Coverage Ratio (2)
December 31, 2017	5.50	2.50	2.25
March 31, 2018	4.75	3.25	2.75
March 31, 2019 and thereafter	4.50	3.25	2.75


(1)	Amount represents the maximum ratio for the period presented.


(2)	Amount represents the minimum ratio for the period presented.

On February 5, 2018, we amended our Credit Agreement. The amendment, among other things, amended the defined term “Consolidated EBITDA” to include the “Accrued Blenders Tax Credits” (as defined in the Credit Agreement) solely for the two quarters ending December 31, 2017 and March 31, 2018.

At December 31, 2017, our leverage ratio was approximately 5.13 to 1, our senior secured leverage ratio was approximately 0.35 to 1 and our interest coverage ratio was approximately 2.32 to 1.

At December 31, 2017, we were in compliance with the covenants under the Credit Agreement.

Senior Secured Notes

On August 2, 2017, we amended the note purchase agreement for our senior secured notes with an effective date of June 2, 2017. The amendment, among other things, conforms the financial covenants to match the amended terms of the Credit Agreement and provides for an increase in interest charged if our leverage ratio exceeds certain predetermined levels. In addition, the amendment also restricts us from increasing our distribution rate over the amount paid in the preceding quarter if our interest coverage ratio is less than 3.00 to 1.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Repurchases

On December 29, 2017, we repurchased all of the remaining outstanding Senior Secured Notes. The following table summarizes repurchases of Senior Secured Notes for the periods indicated:



	Three Months Ended			Nine Months Ended
	December 31,			December 31,
	2017			2017
	(in thousands)
Senior Secured Notes
Notes repurchased	$	175,500		$	230,500
Cash paid (excluding payments of accrued interest)	$	192,979		$	250,179
Loss on early extinguishment of debt (1)	$	(20,807	)	$	(23,971	)


(1)	Loss on the early extinguishment of debt for the Senior Secured Notes during the three months and nine months ended December 31, 2017 are net of debt issuance costs of $3.3 million and $4.3 million, respectively.

Prior to the December 29, 2017 repurchase of all of the remaining outstanding Senior Secured Notes, we made a semi-annual principal installment payment of $19.5 million on December 19, 2017.

Senior Unsecured Notes

Registration Rights

In connection with the issuance of the 7.50% senior notes due 2023 (the “2023 Notes”) and the 6.125% senior notes due 2025 (the “2025 Notes”), we entered into a registration rights agreement in which we agreed to file a registration statement with the SEC so that the holders can exchange the 2023 Notes and the 2025 Notes for registered notes that have substantially identical terms as the 2023 Notes and the 2025 Notes and evidence the same indebtedness of the 2023 Notes and the 2025 Notes. In addition, the subsidiary guarantors agreed to exchange the guarantee related to the 2023 Notes and the 2025 Notes for a registered guarantee having substantially the same terms as the original guarantee. We filed a registration statement for both the 2023 Notes and the 2025 Notes, and the related guarantees, with the SEC which became effective on July 11, 2017 and 99.98% of the 2023 Notes and 99.98% of the 2025 Notes were exchanged on August 8, 2017.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Repurchases

The following table summarizes repurchases of Senior Unsecured Notes for the periods indicated:



	Three Months Ended			Nine Months Ended
	December 31,			December 31,
	2017			2017
	(in thousands)
2019 Notes
Notes repurchased	$	—		$	18,677
Cash paid (excluding payments of accrued interest)	$	—		$	18,641
Loss on early extinguishment of debt (1)	$	—		$	(102	)

2023 Notes
Notes repurchased	$	16,954		$	43,411
Cash paid (excluding payments of accrued interest)	$	17,434		$	42,893
Loss on early extinguishment of debt (2)	$	(730	)	$	(135	)

2025 Notes
Notes repurchased	$	71,793		$	87,493
Cash paid (excluding payments of accrued interest)	$	70,248		$	84,356
Gain on early extinguishment of debt (3)	$	396		$	1,729


(1)	Loss on the early extinguishment of debt for the 2019 Notes during the nine months ended December 31, 2017 are net of debt issuance costs of $0.1 million.


(2)	Loss on the early extinguishment of debt for the 2023 Notes during the three months and nine months ended December 31, 2017 are net of debt issuance costs of $0.2 million and $0.7 million, respectively.


(3)	Gain on the early extinguishment of debt for the 2025 Notes during the three months and nine months ended December 31, 2017 are net of debt issuance costs of $1.1 million and $1.4 million, respectively.

At December 31, 2017, we were in compliance with the covenants under the indentures for all of the senior unsecured notes.

Other Long-Term Debt

We have executed various non-interest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. These instruments have an aggregate principal balance of $5.4 million at December 31, 2017, and the implied interest rates on these instruments range from 1.91% to 7.00% per year. We also have certain notes payable related to equipment financing. These instruments have an aggregate principal balance of $6.3 million at December 31, 2017, and the interest rates on these instruments range from 4.13% to 7.10% per year.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at December 31, 2017:



Fiscal Year Ending March 31,	Revolving Credit Facility		Senior Unsecured Notes		Other Long-Term Debt		Total
	(in thousands)
2018 (three months)	$	—	$	—	$	604	$	604
2019	—		—		2,939		2,939
2020	—		360,781		2,318		363,099
2021	—		—		5,470		5,470
2022	1,139,500		367,048		286		1,506,834
Thereafter	—		1,069,096		67		1,069,163
Total	$	1,139,500	$	1,796,925	$	11,684	$	2,948,109

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, is not expected to 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.

Environmental Matters

Our unaudited condensed consolidated balance sheet at December 31, 2017 includes a liability, measured on an undiscounted basis, of $2.3 million related to environmental matters, which is recorded within accrued expenses and other payables in our unaudited condensed consolidated balance sheet. 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 we will not incur significant costs. 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.

As previously disclosed, the U.S. Environmental Protection Agency (“EPA”) had informed NGL Crude Logistics, LLC, formerly known as Gavilon, LLC (“Gavilon Energy”), of alleged violations in 2011 by Gavilon Energy of the Clean Air Act’s renewable fuel standards regulations (prior to its acquisition by us in December 2013). On October 4, 2016, the U.S. Department of Justice, acting at the request of the EPA, filed a civil complaint in the Northern District of Iowa against Gavilon Energy and one of its then suppliers, Western Dubuque Biodiesel LLC (“Western Dubuque”). Consistent with the earlier allegations by the EPA, the civil complaint related to transactions between Gavilon Energy and Western Dubuque and the generation of biodiesel renewable identification numbers (“RINs”) sold by Western Dubuque to Gavilon Energy in 2011. On December 19, 2016, we filed a motion to dismiss the complaint. On January 9, 2017, the EPA filed an amended complaint. The amended complaint seeks an order declaring Western Dubuque’s RINs invalid and requiring the defendants to retire an equivalent number of valid RINs and that the defendants pay statutory civil penalties. On January 23, 2017, we filed a motion to dismiss the amended complaint, which was denied on May 24, 2017. On October 17, 2017, the EPA filed a motion for partial summary judgment against Gavilon Energy. Consistent with our position against the previous EPA allegations, we deny the allegations in the amended civil complaint and that the EPA is entitled to summary judgment and we intend to continue vigorously defending ourselves in the civil action. However, at this time we are unable to determine the outcome of this action or its significance to us.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Asset Retirement Obligations

We have contractual and regulatory obligations at certain facilities for which we have to perform remediation, dismantlement, or removal activities when the assets are retired. Our liability for asset retirement obligations is discounted to present value. To calculate the liability, we make estimates and assumptions about the retirement cost and the timing of retirement. Changes in our assumptions and estimates may occur as a result of the passage of time and the occurrence of future events. The following table summarizes changes in our asset retirement obligation, which is reported within other noncurrent liabilities in our unaudited condensed consolidated balance sheets (in thousands):



Balance at March 31, 2017	$	8,181
Liabilities incurred	422
Liabilities assumed in acquisitions	21
Liabilities settled	(549		)
Accretion expense	655
Balance at December 31, 2017	$	8,730

In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certain other assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminable. We will record an asset retirement obligation for these assets in the periods in which settlement dates are reasonably determinable.

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment. The following table summarizes future minimum lease payments under these agreements at December 31, 2017 (in thousands):



Fiscal Year Ending March 31,
2018 (three months)	$	34,721
2019	120,928
2020	107,342
2021	93,662
2022	66,036
Thereafter	94,023
Total	$	516,712

Rental expense relating to operating leases was $31.1 million and $32.0 million during the three months ended December 31, 2017 and 2016, respectively, and $94.9 million and $88.9 million during the nine months ended December 31, 2017 and 2016, respectively.

Pipeline Capacity Agreements

We have executed noncancelable agreements with crude oil pipeline operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity. Under certain agreements we have the ability to recover minimum shipping fees previously paid if our shipping volumes exceed the minimum monthly shipping commitment during each month remaining under the agreement, with some contracts containing provisions that allow us to continue shipping up to six months after the maturity date of the contract in order to recapture previously paid minimum shipping delinquency fees. We currently have an asset recorded in other noncurrent assets in our unaudited condensed consolidated balance sheet for minimum shipping fees paid in previous periods that are expected to be recovered in future periods by exceeding the minimum monthly volumes (see Note 2).

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

The following table summarizes future minimum throughput payments under these agreements at December 31, 2017 (in thousands):



Fiscal Year Ending March 31,
2018 (three months)	$	13,001
2019	52,042
2020	42,351
Total	$	107,394

Construction Commitments

At December 31, 2017, we had construction commitments of $6.2 million.

Sales and Purchase Contracts

We have entered into product sales and purchase contracts for which we expect the parties to physically settle and deliver the inventory in future periods.

At December 31, 2017, we had the following commodity purchase commitments (in thousands):



	Crude Oil (1)			Natural Gas Liquids
	Value		Volume (in barrels)	Value		Volume (in gallons)
Fixed-Price Commodity Purchase Commitments:
2018 (three months)	$	51,001	899	$	20,600	26,213
2019	—		—	1,341		2,268
Total	$	51,001	899	$	21,941	28,481

Index-Price Commodity Purchase Commitments:
2018 (three months)	$	427,214	7,386	$	310,124	319,467
2019	790,287		14,640	46,559		50,644
2020	511,636		10,395	—		—
2021	438,851		9,314	—		—
2022	357,603		7,729	—		—
Thereafter	447,158		9,592	—		—
Total	$	2,972,749	59,056	$	356,683	370,111


(1)	Our crude oil index-price purchase commitments exceed our crude oil index-price sales commitments (presented below) due primarily to our long-term purchase commitments for crude oil that we purchase and ship on the Grand Mesa pipeline. As these purchase commitments are deliver-or-pay contracts, we have not entered into corresponding long-term sales contracts for volumes we may not receive.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At December 31, 2017, we had the following commodity sale commitments (in thousands):



	Crude Oil			Natural Gas Liquids
	Value		Volume (in barrels)	Value		Volume (in gallons)
Fixed-Price Commodity Sale Commitments:
2018 (three months)	$	63,247	1,149	$	94,582	103,982
2019	—		—	9,521		12,298
2020	—		—	162		215
Total	$	63,247	1,149	$	104,265	116,495

Index-Price Commodity Sale Commitments:
2018 (three months)	$	468,661	7,872	$	285,758	247,918
2019	389,596		7,311	7,914		7,685
2020	59,885		1,070	—		—
Total	$	918,142	16,253	$	293,672	255,603

We account for the contracts shown in the tables above using the normal purchase and normal sale election. 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 tables 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 in our unaudited condensed consolidated balance sheet and are not included in the tables above. These contracts are included in the derivative disclosures in Note 11, and represent $33.4 million of our prepaid expenses and other current assets and $31.7 million of our accrued expenses and other payables at December 31, 2017.

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. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest. Our general partner is not required to guarantee or pay any of our debts and obligations.

General Partner Contributions

In connection with the issuance of common units for the vesting of restricted units and the warrants that were exercised for common units during the nine months ended December 31, 2017, we issued 905 notional units to our general partner for less than $0.1 million in order to maintain its 0.1% interest in us.

Common Unit Repurchase Program

On August 29, 2017, the board of directors of our general partner authorized a common unit repurchase program, under which we may repurchase up to $15.0 million of our outstanding common units through December 31, 2017 from time to time in the open market or in other privately negotiated transactions. During the three months ended December 31, 2017, we repurchased 323,213 common units for an aggregate price of $3.8 million, including commissions. During the nine months ended December 31, 2017, we repurchased 1,516,848 common units for an aggregate price of $15.0 million, including commissions.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Our Distributions

The following table summarizes distributions declared on our common units during the last four quarters:



Date Declared	Record Date	Date Paid/Payable	Amount Per Unit		Amount Paid/Payable to Limited Partners		Amount Paid/Payable to General Partner
					(in thousands)		(in thousands)
April 24, 2017	May 8, 2017	May 15, 2017	$	0.3900	$	46,870	$	80
July 20, 2017	August 4, 2017	August 14, 2017	$	0.3900	$	47,460	$	81
October 19, 2017	November 6, 2017	November 14, 2017	$	0.3900	$	47,000	$	81
January 23, 2018	February 6, 2018	February 14, 2018	$	0.3900	$	47,223	$	81

Class A Convertible Preferred Units

On April 21, 2016, we received net proceeds of $235.0 million (net of offering costs of $5.0 million) in connection with the issuance of 19,942,169 Class A Convertible Preferred Units (“Class A Preferred Units”) and 4,375,112 warrants.

We allocated the net proceeds on a relative fair value basis to the Class A Preferred Units, which includes the value of a beneficial conversion feature, and the warrants. Accretion for the beneficial conversion feature, recorded as a deemed distribution, was $5.0 million and $2.5 million during the three months ended December 31, 2017 and 2016, respectively, and $12.3 million and $6.3 million during the nine months ended December 31, 2017 and 2016, respectively.

The holders of the warrants may exercise one-third of the warrants from and after the first anniversary of the original issue date, another one-third of the warrants from and after the second anniversary and the final one-third of the warrants from and after the third anniversary. The warrants have an exercise price of $0.01 and an eight year term. During the nine months ended December 31, 2017, 607,653 warrants were exercised for common units and we received proceeds of less than $0.1 million. In addition, we repurchased 850,716 unvested warrants for a total purchase price of $10.5 million on June 23, 2017. As of December 31, 2017, we had 2,916,743 warrants outstanding.

We pay a cumulative, quarterly distribution in arrears at an annual rate of 10.75% on the Class A Preferred Units to the extent declared by the board of directors of our general partner.

The following table summarizes distributions declared on our Class A Preferred Units during the last four quarters:



		Amount Paid/Payable to Class A
Date Declared	Date Paid/Payable	Preferred Unitholders
		(in thousands)
April 24, 2017	May 15, 2017	$	6,449
July 20, 2017	August 14, 2017	$	6,449
October 19, 2017	November 14, 2017	$	6,449
January 23, 2018	February 14, 2018	$	6,449

Class B Preferred Units

During the nine months ended December 31, 2017, we issued 8,400,000 of our 9.00% Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”) representing limited partner interests at a price of $25.00 per unit for net proceeds of $202.7 million (net of the underwriters’ discount of $6.6 million and offering costs of $0.7 million).

At any time on or after July 1, 2022, we may redeem our Class B Preferred Units, in whole or in part, at a redemption price of $25.00 per Class B Preferred Unit plus an amount equal to all accumulated and unpaid distributions to, but not including, the date of redemption, whether or not declared. We may also redeem the Class B Preferred Units upon a change of control as defined in our partnership agreement. If we choose not to redeem the Class B Preferred Units, the Class B preferred

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

unitholders may have the ability to convert the Class B Preferred Units to common units at the then applicable conversion rate. Class B preferred unitholders have no voting rights except with respect to certain matters set forth in our partnership agreement.

Distributions on the Class B Preferred Units are payable on the 15th day of each January, April, July and October of each year to holders of record on the first day of each payment month. The initial distribution rate for the Class B Preferred Units from and including the date of original issue to, but not including, July 1, 2022 is 9.00% per year of the $25.00 liquidation preference per unit (equal to $2.25 per unit per year). On and after July 1, 2022, distributions on the Class B Preferred Units will accumulate at a percentage of the $25.00 liquidation preference equal to the applicable three-month LIBOR plus a spread of 7.213%. On September 18, 2017, the board of directors of our general partner declared a distribution for the three months ended September 30, 2017 of $5.7 million. The distribution was paid to the holders of the Class B Preferred Units on October 16, 2017. On December 19, 2017, the board of directors of our general partner declared a distribution for the three months ended December 31, 2017 of $4.7 million to the holders of record on December 29, 2017. The distribution amount is included in accrued expenses and other payables in our unaudited condensed consolidated balance sheet at December 31, 2017. The distribution was paid to the holders of the Class B Preferred Units on January 15, 2018.

Amended and Restated Partnership Agreement

On June 13, 2017, NGL Energy Holdings LLC executed the Fourth Amended and Restated Agreement of Limited Partnership. The preferences, rights, powers and duties of holders of the Class B Preferred Units are defined in the amended and restated partnership agreement. The Class B Preferred Units rank senior to the common units, with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up, and are on parity with the Class A Preferred Units. The Class B Preferred Units have no stated maturity but we may redeem the Class B Preferred Units at any time on or after July 1, 2022 or upon the occurrence of a change in control.

At-The-Market Program

On August 24, 2016, we entered into an equity distribution agreement in connection with an at-the-market program (the “ATM Program”) pursuant to which we may issue and sell up to $200.0 million of common units. We did not issue any common units under the ATM Program during the nine months ended December 31, 2017, and approximately $134.7 million remained available for sale under the ATM Program at December 31, 2017.

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 vest in tranches, subject to the continued service of the recipients. The awards may also vest upon a change of control, at the discretion of the board of directors of our general partner. No distributions accrue to or are paid on the restricted units during the vesting period.

The restricted units include both awards that: (i) vest contingent on the continued service of the recipients through the vesting date (the “Service Awards”) and (ii) vest contingent both on the continued service of the recipients through the vesting date and also on the performance of our common units relative to other entities in the Alerian MLP Index (the “Index”) over specified periods of time (the “Performance Awards”).

On April 1, 2017, we made an accounting policy election to account for actual forfeitures, rather than estimate forfeitures each period (as previously required). As a result, the cumulative effect adjustment, which represents the differential between the amount of compensation expense previously recorded and the amount that would have been recorded without assuming forfeitures, had no impact on our consolidated financial statements.

The following table summarizes the Service Award activity during the nine months ended December 31, 2017:



Unvested Service Award units at March 31, 2017	2,708,500
Units granted	1,036,202
Units vested and issued	(1,855,102	)
Units forfeited	(90,000	)
Unvested Service Award units at December 31, 2017	1,799,600

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

In connection with the vesting of certain restricted units during the nine months ended December 31, 2017, we canceled 41,650 of the newly-vested common units in satisfaction of $0.6 million of employee tax liability paid by us. Pursuant to the terms of the LTIP, these canceled units are available for future grants under the LTIP.

The following table summarizes the scheduled vesting of our unvested Service Award units at December 31, 2017:



Fiscal Year Ending March 31,
2018 (three months)		315,500
2019		896,750
2020		584,600
2021		2,750
Total		1,799,600

Service Awards are valued at the closing price as of the grant date less the present value of the expected distribution stream over the vesting period using a risk-free interest rate. We record the expense for each Service Award on a straight-line basis over the requisite period for the entire award (that is, over the requisite service period of the last separately vesting portion of the award), ensuring that the amount of compensation cost recognized at any date at least equals the portion of the grant-date value of the award that is vested at that date.

In December 2017, the compensation committee of the board of directors of our general partner decided that the vesting of all future grants would be split between dates in February and November instead of the entire grant vesting in July, which was the month the units generally vested. In addition, employees with unvested Service Awards were given an option to switch the vesting of their outstanding Service Awards and split the awards to vest in February and November or keep the vesting in July. For example, if an employee elected to change the vesting of their outstanding Service Awards, an award that was originally scheduled to vest in July 2018 would now be split so that half of the award will vest in February 2018 and the other half in November 2018. The Service Awards of individuals that elected to split the vesting are considered to be modified. The impact of the modification was not material to the current or future unit based compensation expense.

During the three months ended December 31, 2017 and 2016, we recorded compensation expense related to Service Award units of $3.1 million and $4.8 million, respectively. During the nine months ended December 31, 2017 and 2016, we recorded compensation expense related to Service Award units of $11.7 million and $51.5 million, respectively.

Of the restricted units granted and vested during the nine months ended December 31, 2017, 964,702 units were granted as a bonus for performance during the fiscal year ended March 31, 2017. The total amount of these bonus payments were $12.4 million, of which we had accrued $5.5 million as of March 31, 2017.

The following table summarizes the estimated future expense we expect to record on the unvested Service Award units at December 31, 2017 (in thousands):



Fiscal Year Ending March 31,
2018 (three months)	$	3,586
2019	8,909
2020	3,175
2021	18
Total	$	15,688

During April 2015, our general partner granted Performance Award units to certain employees. The number of Performance Award units that will vest is contingent on the performance of our common units relative to the performance of the other entities in the Index. Performance will be calculated based on the return on our common units (including changes in the market price of the common units and distributions paid during the performance period) relative to the returns on the common units of the other entities in the Index. As of December 31, 2017, performance will be measured over the following periods:

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Vesting Date of Tranche		Performance Period for Tranche
July 1, 2018		July 1, 2015 through June 30, 2018
July 1, 2019		July 1, 2016 through June 30, 2019

The following table summarizes the Performance Award activity during the nine months ended December 31, 2017:



Unvested Performance Award units at March 31, 2017	1,189,000
Units forfeited	(426,000	)
Unvested Performance Award units at December 31, 2017	763,000

During the July 1, 2014 through June 30, 2017 performance period, the return on our common units was below the return of the 50th percentile of our peer companies in the Index. As a result, no Performance Award units vested on July 1, 2017 and performance units with the July 1, 2017 vesting date are considered to be forfeited.

The fair value of the Performance Awards is estimated using a Monte Carlo simulation at the grant date. We record the expense for each of the tranches of the Performance Awards on a straight-line basis over the period beginning with the grant date and ending with the vesting date of the tranche. Any Performance Awards that do not become earned Performance Awards will terminate, expire and otherwise be forfeited by the participants. During the three months ended December 31, 2017 and 2016, we recorded compensation expense related to Performance Award units of $1.1 million and $2.1 million, respectively. During the nine months ended December 31, 2017 and 2016, we recorded compensation expense related to Performance Awards units of $4.5 million and $5.2 million, respectively.

The following table summarizes the estimated future expense we expect to record on the unvested Performance Award units at December 31, 2017 (in thousands):



Fiscal Year Ending March 31,
2018 (three months)	$	1,266
2019	3,078
2020	624
Total	$	4,968

At December 31, 2017, approximately 2.4 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.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Commodity Derivatives

The following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported in our unaudited condensed consolidated balance sheet at the dates indicated:



	December 31, 2017						March 31, 2017
	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
	(in thousands)
Level 1 measurements	$	9,981		$	(41,702	)	$	2,590		$	(21,113	)
Level 2 measurements	33,645			(37,382		)	38,729			(27,799		)
	43,626			(79,084		)	41,319			(48,912		)

Netting of counterparty contracts (1)	(8,470		)	8,470			(1,508		)	1,508
Net cash collateral (held) provided	(791		)	33,233			(1,035		)	19,604
Commodity derivatives	$	34,365		$	(37,381	)	$	38,776		$	(27,800	)


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

The following table summarizes the accounts that include our commodity derivative assets and liabilities in our unaudited condensed consolidated balance sheets at the dates indicated:



	December 31, 2017			March 31, 2017
	(in thousands)
Prepaid expenses and other current assets	$	34,283		$	38,711
Other noncurrent assets	82			65
Accrued expenses and other payables	(34,713		)	(27,622		)
Other noncurrent liabilities	(2,668		)	(178		)
Net commodity derivative (liability) asset	$	(3,016	)	$	10,976

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

The following table summarizes our open commodity derivative contract positions at the dates indicated. We do not account for these derivatives as hedges.



Contracts	Settlement Period	Net Long (Short) Notional Units (in barrels)		Fair Value of Net Assets (Liabilities)
		(in thousands)
At December 31, 2017:
Cross-commodity (1)	January 2018–March 2018	(21	)	$	(1,587	)
Crude oil fixed-price (2)	January 2018–December 2019	(1,243	)	(7,536		)
Propane fixed-price (2)	January 2018–December 2018	210		1,942
Refined products fixed-price (2)	January 2018–January 2020	(4,743	)	(29,363		)
Refined products index (2)	January 2018–June 2018	(13	)	(51		)
Other	January 2018–March 2022			1,137
				(35,458		)
Net cash collateral provided				32,442
Net commodity derivative liability				$	(3,016	)

At March 31, 2017:
Crude oil fixed-price (2)	April 2017–May 2017	(800	)	$	(55	)
Propane fixed-price (2)	April 2017–December 2018	220		1,082
Refined products fixed-price (2)	April 2017–January 2019	(4,682	)	(7,729		)
Refined products index (2)	April 2017–December 2017	(18	)	(103		)
Other	April 2017–March 2022			(788		)
				(7,593		)
Net cash collateral provided				18,569
Net commodity derivative asset				$	10,976


(1)	We may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. These contracts are derivatives we have entered into as an economic hedge against the risk of one commodity price moving relative to another commodity price.


(2)	We may have fixed price physical purchases, including inventory, offset by floating price physical sales or floating price physical purchases offset by fixed price physical sales. These contracts are derivatives we have entered into as an economic hedge against the risk of mismatches between fixed and floating price physical obligations.

During the three months and nine months ended December 31, 2017, we recorded net losses of $64.9 million and $99.8 million, respectively, and during the three months and nine months ended December 31, 2016, we recorded net losses of $57.7 million and $102.6 million, respectively, from our commodity derivatives to cost of sales in our unaudited condensed consolidated statements of operations.

Credit Risk

We have credit policies 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 industry standard master netting agreements, which allow for offsetting counterparty receivable and payable balances for certain transactions. At December 31, 2017, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, as the counterparties may be similarly affected by changes in economic, regulatory or other conditions. If a counterparty does not perform on a contract, we may not realize amounts that have been recorded in our unaudited condensed consolidated balance sheets and recognized in our net income.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Interest Rate Risk

Fair Value of Fixed-Rate Notes

The following table provides fair value estimates of our fixed-rate notes at December 31, 2017 (in thousands):



Senior unsecured notes:
5.125% Notes due 2019	$	367,997
6.875% Notes due 2021	$	374,045
7.500% Notes due 2023	$	681,621
6.125% Notes due 2025	$	405,804

For the senior unsecured notes, the fair value estimates were developed based on publicly traded quotes and would be classified as Level 1 in the fair value hierarchy.

Note 12—Segments

The following table summarizes certain financial data related to our segments. Transactions between segments are recorded based on prices negotiated between the segments.

The “Corporate and Other” category in the table below includes certain corporate expenses that are not allocated to the reportable segments.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



	Three Months Ended December 31,						Nine Months Ended December 31,
	2017			2016			2017			2016
	(in thousands)
Revenues:
Crude Oil Logistics:
Crude oil sales	$	556,001		$	366,569		$	1,446,560		$	1,123,169
Crude oil transportation and other	33,017			20,914			89,318			43,020
Elimination of intersegment sales	(4,011		)	(1,577		)	(8,934		)	(4,447		)
Total Crude Oil Logistics revenues	585,007			385,906			1,526,944			1,161,742
Water Solutions:
Service fees	41,045			28,268			109,648			82,493
Recovered hydrocarbons	17,021			6,387			37,427			19,264
Other revenues	5,958			5,704			14,948			14,088
Total Water Solutions revenues	64,024			40,359			162,023			115,845
Liquids:
Propane sales	403,236			260,562			733,684			458,646
Butane sales	228,535			146,514			408,312			267,769
Other product sales	123,677			89,225			310,389			217,405
Other revenues	6,166			7,704			16,106			22,926
Elimination of intersegment sales	(52,570		)	(33,730		)	(88,510		)	(57,162		)
Total Liquids revenues	709,044			470,275			1,379,981			909,584
Retail Propane:
Propane sales	124,466			96,699			221,102			174,510
Distillate sales	22,806			19,569			39,037			35,613
Other revenues	12,797			12,418			31,733			30,056
Elimination of intersegment sales	(44		)	(32		)	(75		)	(48		)
Total Retail Propane revenues	160,025			128,654			291,797			240,131
Refined Products and Renewables:
Refined products sales	2,845,482			2,258,317			8,493,357			6,409,889
Renewables sales	99,436			123,065			313,366			325,377
Service fees	94			50			262			11,195
Elimination of intersegment sales	(138		)	(149		)	(268		)	(293		)
Total Refined Products and Renewables revenues	2,944,874			2,381,283			8,806,717			6,746,168
Corporate and Other	289			164			696			679
Total revenues	$	4,463,263		$	3,406,641		$	12,168,158		$	9,174,149
Depreciation and Amortization:
Crude Oil Logistics	$	20,092		$	16,503		$	61,885		$	34,496
Water Solutions	24,586			27,150			73,847			76,713
Liquids	6,247			4,441			18,718			13,315
Retail Propane	11,130			11,379			34,205			31,771
Refined Products and Renewables	323			404			971			1,237
Corporate and Other	962			890			2,801			2,744
Total depreciation and amortization	$	63,340		$	60,767		$	192,427		$	160,276
Operating Income (Loss):
Crude Oil Logistics	$	106,279		$	(9,163	)	$	111,832		$	(28,827	)
Water Solutions	(1,373		)	(11,898		)	(10,075		)	63,136
Liquids	22,290			24,765			(104,589		)	33,092
Retail Propane	23,972			21,772			8,878			10,553
Refined Products and Renewables	(4,791		)	8,209			30,747			169,365
Corporate and Other	(21,846		)	(11,128		)	(56,031		)	(66,690		)
Total operating income (loss)	$	124,531		$	22,557		$	(19,238	)	$	180,629

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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



	Three Months Ended December 31,					Nine Months Ended December 31,
	2017		2016			2017		2016
	(in thousands)
Crude Oil Logistics	$	14,788	$	42,758		$	26,509	$	147,460
Water Solutions	22,556		18,275			56,996		86,628
Liquids	1,188		1,736			2,868		14,897
Retail Propane	14,527		16,196			49,242		94,170
Refined Products and Renewables	—		(945		)	—		42,175
Corporate and Other	625		375			1,334		2,107
Total	$	53,684	$	78,395		$	136,949	$	387,437

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



	December 31, 2017		March 31, 2017
	(in thousands)
Long-lived assets, net:
Crude Oil Logistics	$	1,661,020	$	1,724,805
Water Solutions	1,239,578		1,261,944
Liquids	485,454		619,204
Retail Propane	457,031		547,960
Refined Products and Renewables	210,534		215,637
Corporate and Other	33,338		36,395
Total	$	4,086,955	$	4,405,945

Total assets:
Crude Oil Logistics	$	2,269,632	$	2,538,768
Water Solutions	1,303,873		1,301,415
Liquids	901,904		767,597
Retail Propane	660,850		622,859
Refined Products and Renewables	1,087,499		988,073
Corporate and Other	92,628		101,667
Total	$	6,316,386	$	6,320,379

Note 13—Transactions with Affiliates

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

We purchase ethanol from E Energy Adams, LLC, an equity method investee (see Note 2). These transactions are reported within cost of sales in our unaudited condensed consolidated statements of operations.

Certain members of our management and members of their families as well as other associated parties own interests in entities from which we have purchased products and services and to which we have sold products and services. During the nine months ended December 31, 2017, $0.8 million of these transactions were capital expenditures and were recorded as increases to property, plant and equipment.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

The following table summarizes these related party transactions for the periods indicated:



	Three Months Ended December 31,				Nine Months Ended December 31,
	2017		2016		2017		2016
	(in thousands)
Sales to SemGroup	$	178	$	150	$	408	$	3,734
Purchases from SemGroup	$	1,050	$	1,911	$	3,978	$	5,874
Sales to equity method investees	$	98	$	95	$	294	$	595
Purchases from equity method investees	$	18,373	$	33,538	$	66,842	$	91,530
Sales to entities affiliated with management	$	64	$	53	$	204	$	205
Purchases from entities affiliated with management	$	193	$	2,580	$	1,540	$	14,316

Accounts receivable from affiliates consist of the following at the dates indicated:



	December 31, 2017		March 31, 2017
	(in thousands)
Receivables from SemGroup	$	83	$	6,668
Receivables from NGL Energy Holdings LLC	3,413		—
Receivables from equity method investees	2		15
Receivables from entities affiliated with management	19		28
Total	$	3,517	$	6,711

Amounts as of December 31, 2017 in the table above exclude accounts receivable from affiliates related to the potential sale of a portion of the Retail Propane segment, as these amounts have been classified as current assets held for sale in our unaudited condensed consolidated balance sheet (see Note 14).

Accounts payable to affiliates consist of the following at the dates indicated:



	December 31, 2017		March 31, 2017
	(in thousands)
Payables to SemGroup	$	390	$	6,571
Payables to equity method investees	81		1,306
Payables to entities affiliated with management	3		41
Total	$	474	$	7,918

At December 31, 2017 and March 31, 2017, we had a loan receivable from Victory Propane, an equity method investee (see Note 2), of $0.3 million (net of our proportionate share of their losses of $0.2 million, as described in Note 2) and $3.2 million, respectively, with an initial maturity date of March 31, 2021, which can be extended for successive one-year periods unless one of the parties terminates the loan agreement.

Other Related Party Transactions

On June 23, 2017, we repurchased outstanding warrants, as discussed further in Note 10, from funds managed by Oaktree Capital Management, L.P., who are represented on the board of directors of our general partner.

During the three months ended December 31, 2017 we completed a transaction with Victory Propane, an equity method investee (See Note 2), to purchase Victory Propane’s Michigan assets. We paid Victory Propane $6.4 million in cash and received current assets, property, plant and equipment and customers. The allocation of the consideration was as follows:

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Current assets	$	276
Property, plant and equipment	1,366
Intangible assets (customer relationships)	4,782
Fair value of net assets acquired	$	6,424

Victory Propane recognized a gain on this transaction. As all intra-entity profits and losses are eliminated between an investor and investee until realized, we have eliminated our proportionate share of the gain from this transaction on our books. As a result, our underlying equity in the net assets of Victory Propane exceeds our investment (see Note 2), and this difference will be amortized as income over the remaining life of the noncurrent assets acquired or until they are sold.

Victory Propane used a portion of the proceeds to pay off the outstanding balance of their note payable to us of $4.2 million and paid $2.0 million in distributions to the owners, including us.

Note 14—Assets and Liabilities Held for Sale

Potential Sale of a Portion of Retail Propane Business

On November 7, 2017, we entered into a definitive agreement with DCC LPG, a division of DCC plc, to sell a portion of our Retail Propane segment for $200 million in cash, adjusted for working capital at closing. We will retain this business through closing, which is expected to be March 31, 2018. The Retail Propane businesses subject to this transaction are comprised of our operations across the Mid-Continent and Western portions of the United States. We will retain our Retail Propane businesses located in the Eastern and Southeastern section of the United States. At December 31, 2017, we met the criteria for classifying the assets and liabilities of the Retail Propane businesses subject to this transaction as held for sale in our unaudited condensed consolidated balance sheet. As a result, we have not recorded any depreciation or amortization expense for the Retail Propane businesses subject to this transaction since they were classified as held for sale. In November 2017, we received a deposit of $20 million from DCC LPG related to the sale which is recorded in accrued expenses and other payables in our December 31, 2017 unaudited condensed consolidated balance sheet. As part of the agreement, we issued a letter of credit to DCC LPG for the amount of their deposit.

The following table summarizes the major classes of assets and liabilities classified as held for sale at December 31, 2017 (in thousands):



Assets Held for Sale
Cash and cash equivalents	$	1,985
Accounts receivable-trade, net	13,336
Accounts receivable-affiliates	1
Inventories	6,273
Prepaid expenses and other current assets	2,437
Property, plant and equipment, net	61,137
Goodwill	24,959
Intangible assets, net	21,463
Total assets held for sale	$	131,591

Liabilities Held for Sale
Accounts payable-trade	$	686
Accrued expenses and other payables	2,565
Advance payments received from customers	13,163
Other liabilities	160
Total liabilities held for sale	$	16,574

As this sale transaction does not represent a strategic shift that will have a major effect on our operations or financial results, operations related to this portion of our Retail Propane segment have not been classified as discontinued operations.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

The Retail Propane businesses subject to this transaction had income before taxes of $3.4 million for the nine months ended December 31, 2017.

Note 15—Unaudited Condensed Consolidating Guarantor and Non-Guarantor Financial Information

Certain of our wholly owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the senior unsecured notes (see Note 8). Pursuant to Rule 3-10 of Regulation S-X, we have presented in columnar format the unaudited condensed consolidating financial information for NGL Energy Partners LP (Parent), NGL Energy Finance Corp., the guarantor subsidiaries on a combined basis, and the non-guarantor subsidiaries on a combined basis in the tables below. NGL Energy Partners LP and NGL Energy Finance Corp. are co-issuers of the senior unsecured notes. Since NGL Energy Partners LP received the proceeds from the issuance of the senior unsecured notes, all activity has been reflected in the NGL Energy Partners LP (Parent) column 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 senior unsecured notes.

There are no significant restrictions that prevent the parent or any of the guarantor subsidiaries from obtaining funds from their respective subsidiaries by dividend or loan. None of the assets of the guarantor subsidiaries (other than the investments in non-guarantor subsidiaries) are restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended.

For purposes of the tables below, (i) the unaudited 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 (from) consolidated entities are reported on a net basis within net changes in advances with consolidated entities in the unaudited condensed consolidating statement of cash flow tables below.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Balance Sheet

(in Thousands)



	December 31, 2017
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	14,994	$	—	$	11,179		$	2,296		$	—		$	28,469
Accounts receivable-trade, net of allowance for doubtful accounts	—		—		1,060,207			3,700			—			1,063,907
Accounts receivable-affiliates	—		—		3,517			—			—			3,517
Inventories	—		—		644,154			946			—			645,100
Prepaid expenses and other current assets	—		—		97,058			337			—			97,395
Assets held for sale	—		—		131,742			—			(151		)	131,591
Total current assets	14,994		—		1,947,857			7,279			(151		)	1,969,979
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,676,248			32,435			—			1,708,683
GOODWILL	—		—		1,300,560			12,757			—			1,313,317
INTANGIBLE ASSETS, net of accumulated amortization	—		—		1,051,683			13,272			—			1,064,955
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		16,369			—			—			16,369
NET INTERCOMPANY RECEIVABLES (PAYABLES)	2,116,433		—		(2,095,213		)	(21,220		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,727,675		—		24,623			—			(1,752,298		)	—
LOAN RECEIVABLE-AFFILIATE	—		—		318			—			—			318
OTHER NONCURRENT ASSETS	—		—		242,765			—			—			242,765
Total assets	$	3,859,102	$	—	$	4,165,210		$	44,523		$	(1,752,449	)	$	6,316,386
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	—	$	—	$	865,117		$	1,651		$	—		$	866,768
Accounts payable-affiliates	1		—		473			—			—			474
Accrued expenses and other payables	34,879		—		194,937			936			—			230,752
Advance payments received from customers	—		—		46,326			675			(151		)	46,850
Current maturities of long-term debt	—		—		2,887			373			—			3,260
Liabilities held for sale	—		—		16,574			—			—			16,574
Total current liabilities	34,880		—		1,126,314			3,635			(151		)	1,164,678
LONG-TERM DEBT, net of debt issuance costs and current maturities	1,774,042		—		1,147,180			744			—			2,921,966
OTHER NONCURRENT LIABILITIES	—		—		164,041			4,240			—			168,281
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS	76,056		—		—			—			—			76,056
REDEEMABLE NONCONTROLLING INTEREST	—		—		—			4,011			—			4,011
EQUITY:
Partners’ equity	1,974,124		—		1,728,919			32,127			(1,759,568		)	1,975,602
Accumulated other comprehensive loss	—		—		(1,244		)	(234		)	—			(1,478		)
Noncontrolling interests	—		—		—			—			7,270			7,270
Total equity	1,974,124		—		1,727,675			31,893			(1,752,298		)	1,981,394
Total liabilities and equity	$	3,859,102	$	—	$	4,165,210		$	44,523		$	(1,752,449	)	$	6,316,386

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Balance Sheet

(in Thousands)



	March 31, 2017
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6,257	$	—	$	2,903		$	3,104		$	—		$	12,264
Accounts receivable-trade, net of allowance for doubtful accounts	—		—		795,479			5,128			—			800,607
Accounts receivable-affiliates	—		—		6,711			—			—			6,711
Inventories	—		—		560,769			663			—			561,432
Prepaid expenses and other current assets	—		—		102,703			490			—			103,193
Total current assets	6,257		—		1,468,565			9,385			—			1,484,207
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,725,383			64,890			—			1,790,273
GOODWILL	—		—		1,437,759			13,957			—			1,451,716
INTANGIBLE ASSETS, net of accumulated amortization	—		—		1,149,524			14,432			—			1,163,956
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		187,423			—			—			187,423
NET INTERCOMPANY RECEIVABLES (PAYABLES)	2,424,730		—		(2,408,189		)	(16,541		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,978,158		—		47,598			—			(2,025,756		)	—
LOAN RECEIVABLE-AFFILIATE	—		—		3,200			—			—			3,200
OTHER NONCURRENT ASSETS	—		—		239,436			168			—			239,604
Total assets	$	4,409,145	$	—	$	3,850,699		$	86,291		$	(2,025,756	)	$	6,320,379
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	—	$	—	$	657,077		$	944		$	—		$	658,021
Accounts payable-affiliates	1		—		7,907			10			—			7,918
Accrued expenses and other payables	42,150		—		164,012			963			—			207,125
Advance payments received from customers	—		—		35,107			837			—			35,944
Current maturities of long-term debt	25,000		—		4,211			379			—			29,590
Total current liabilities	67,151		—		868,314			3,133			—			938,598
LONG-TERM DEBT, net of debt issuance costs and current maturities	2,138,048		—		824,370			1,065			—			2,963,483
OTHER NONCURRENT LIABILITIES	—		—		179,857			4,677			—			184,534
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS	63,890		—		—			—			—			63,890
REDEEMABLE NONCONTROLLING INTEREST	—		—		—			3,072			—			3,072
EQUITY:
Partners’ equity	2,140,056		—		1,979,785			74,545			(2,052,502		)	2,141,884
Accumulated other comprehensive loss	—		—		(1,627		)	(201		)	—			(1,828		)
Noncontrolling interests	—		—		—			—			26,746			26,746
Total equity	2,140,056		—		1,978,158			74,344			(2,025,756		)	2,166,802
Total liabilities and equity	$	4,409,145	$	—	$	3,850,699		$	86,291		$	(2,025,756	)	$	6,320,379

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statement of Operations

(in Thousands)



	Three Months Ended December 31, 2017
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated

REVENUES	$	—		$	—	$	4,454,133		$	10,818		$	(1,688	)	$	4,463,263
COST OF SALES	—			—		4,269,586			4,910			(1,688		)	4,272,808
OPERATING COSTS AND EXPENSES:
Operating	—			—		82,468			2,378			—			84,846
General and administrative	—			—		29,033			185			—			29,218
Depreciation and amortization	—			—		61,961			1,379			—			63,340
(Gain) loss on disposal or impairment of assets, net	—			—		(111,509		)	29			—			(111,480		)
Operating Income	—			—		122,594			1,937			—			124,531
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		3,426			—			—			3,426
Interest expense	(36,019		)	—		(15,752		)	(228		)	209			(51,790		)
Loss on early extinguishment of liabilities, net	(21,141		)	—		—			—			—			(21,141		)
Other income, net	—			—		2,298			18			(209		)	2,107
(Loss) Income Before Income Taxes	(57,160		)	—		112,566			1,727			—			57,133
INCOME TAX EXPENSE	—			—		(364		)	—			—			(364		)
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES	113,416			—		1,214			—			(114,630		)	—
Net Income	56,256			—		113,416			1,727			(114,630		)	56,769
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(89		)	(89		)
LESS: NET INCOME ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS												(424		)	(424		)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(16,219		)	(16,219		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(73		)	(73		)
NET INCOME ALLOCATED TO COMMON UNITHOLDERS	$	56,256		$	—	$	113,416		$	1,727		$	(131,435	)	$	39,964

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statement of Operations

(in Thousands)



	Three Months Ended December 31, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated

REVENUES	$	—		$	—	$	3,393,541		$	14,249		$	(1,149	)	$	3,406,641
COST OF SALES	—			—		3,226,175			2,996			(1,149		)	3,228,022
OPERATING COSTS AND EXPENSES:
Operating	—			—		72,911			4,070			—			76,981
General and administrative	—			—		18,090			190			—			18,280
Depreciation and amortization	—			—		58,091			2,676			—			60,767
Loss (gain) on disposal or impairment of assets, net	—			—		37			(3		)	—			34
Operating Income	—			—		18,237			4,320			—			22,557
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		1,279			—			—			1,279
Interest expense	(26,217		)	—		(15,340		)	(98		)	219			(41,436		)
Other income, net	—			—		20,206			20			(219		)	20,007
(Loss) Income Before Income Taxes	(26,217		)	—		24,382			4,242			—			2,407
INCOME TAX EXPENSE	—			—		(1,114		)	—			—			(1,114		)
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES	27,193			—		3,925			—			(31,118		)	—
Net Income	976			—		27,193			4,242			(31,118		)	1,293
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(317		)	(317		)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(8,906		)	(8,906		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(22		)	(22		)
NET INCOME ALLOCATED TO COMMON UNITHOLDERS	$	976		$	—	$	27,193		$	4,242		$	(40,363	)	$	(7,952	)

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statement of Operations

(in Thousands)



	Nine Months Ended December 31, 2017
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated

REVENUES	$	—		$	—	$	12,150,896		$	20,261		$	(2,999	)	$	12,168,158
COST OF SALES	—			—		11,679,386			9,250			(2,999		)	11,685,637
OPERATING COSTS AND EXPENSES:
Operating	—			—		231,376			5,909			—			237,285
General and administrative	—			—		77,190			499			—			77,689
Depreciation and amortization	—			—		188,893			3,534			—			192,427
(Gain) loss on disposal or impairment of assets, net	—			—		(12,436		)	1,194			—			(11,242		)
Revaluation of liabilities	—			—		5,600			—			—			5,600
Operating Loss	—			—		(19,113		)	(125		)	—			(19,238		)
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		7,270			—			—			7,270
Interest expense	(111,609		)	—		(39,576		)	(681		)	617			(151,249		)
Loss on early extinguishment of liabilities, net	(22,479		)	—		—			—			—			(22,479		)
Other income, net	—			—		6,656			74			(617		)	6,113
Loss Before Income Taxes	(134,088		)	—		(44,763		)	(732		)	—			(179,583		)
INCOME TAX EXPENSE	—			—		(934		)	—			—			(934		)
EQUITY IN NET LOSS OF CONSOLIDATED SUBSIDIARIES	(46,389		)	—		(692		)	—			47,081			—
Net Loss	(180,477		)	—		(46,389		)	(732		)	47,081			(180,517		)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(221		)	(221		)
LESS: NET LOSS ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS												261			261
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(42,001		)	(42,001		)
LESS: NET LOSS ALLOCATED TO GENERAL PARTNER												121			121
LESS: REPURCHASE OF WARRANTS												(349		)	(349		)
NET LOSS ALLOCATED TO COMMON UNITHOLDERS	$	(180,477	)	$	—	$	(46,389	)	$	(732	)	$	4,892		$	(222,706	)

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statement of Operations

(in Thousands)



	Nine Months Ended December 31, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated

REVENUES	$	—		$	—	$	9,142,575		$	33,718		$	(2,144	)	$	9,174,149
COST OF SALES	—			—		8,720,039			5,297			(2,144		)	8,723,192
OPERATING COSTS AND EXPENSES:
Operating	—			—		212,542			12,866			—			225,408
General and administrative	—			—		87,402			675			—			88,077
Depreciation and amortization	—			—		152,140			8,136			—			160,276
Gain on disposal or impairment of assets, net	—			—		(203,406		)	(27		)	—			(203,433		)
Operating Income	—			—		173,858			6,771			—			180,629
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		1,726			—			—			1,726
Revaluation of investments	—			—		(14,365		)	—			—			(14,365		)
Interest expense	(58,907		)	—		(46,238		)	(551		)	380			(105,316		)
Gain on early extinguishment of liabilities, net	8,614			—		22,276			—			—			30,890
Other income, net	—			—		26,196			44			(380		)	25,860
(Loss) Income Before Income Taxes	(50,293		)	—		163,453			6,264			—			119,424
INCOME TAX EXPENSE	—			—		(2,036		)	—			—			(2,036		)
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES	161,590			—		173			—			(161,763		)	—
Net Income	111,297			—		161,590			6,264			(161,763		)	117,388
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(6,091		)	(6,091		)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(20,958		)	(20,958		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(180		)	(180		)
NET INCOME ALLOCATED TO COMMON UNITHOLDERS	$	111,297		$	—	$	161,590		$	6,264		$	(188,992	)	$	90,159

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statements of Comprehensive Income (Loss)

(in Thousands)



	Three Months Ended December 31, 2017
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net income	$	56,256	$	—	$	113,416	$	1,727		$	(114,630	)	$	56,769
Other comprehensive income (loss)	—		—		795		(11		)	—			784
Comprehensive income	$	56,256	$	—	$	114,211	$	1,716		$	(114,630	)	$	57,553



	Three Months Ended December 31, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net income	$	976	$	—	$	27,193	$	4,242		$	(31,118	)	$	1,293
Other comprehensive income (loss)	—		—		568		(23		)	—			545
Comprehensive income	$	976	$	—	$	27,761	$	4,219		$	(31,118	)	$	1,838



	Nine Months Ended December 31, 2017
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
Net loss	$	(180,477	)	$	—	$	(46,389	)	$	(732	)	$	47,081	$	(180,517	)
Other comprehensive income (loss)	—			—		383			(33		)	—		350
Comprehensive loss	$	(180,477	)	$	—	$	(46,006	)	$	(765	)	$	47,081	$	(180,167	)



	Nine Months Ended December 31, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net income	$	111,297	$	—	$	161,590	$	6,264		$	(161,763	)	$	117,388
Other comprehensive income (loss)	—		—		93		(33		)	—			60
Comprehensive income	$	111,297	$	—	$	161,683	$	6,231		$	(161,763	)	$	117,448

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statement of Cash Flows

(in Thousands)



	Nine Months Ended December 31, 2017
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	415,012		$	—	$	(447,316	)	$	36,365		$	4,061
INVESTING ACTIVITIES:
Capital expenditures	—			—		(97,971		)	(1,413		)	(99,384		)
Acquisitions, net of cash acquired	—			—		(49,081		)	(400		)	(49,481		)
Cash flows from settlements of commodity derivatives	—			—		(85,823		)	—			(85,823		)
Proceeds from sales of assets	—			—		33,673			—			33,673
Proceeds from sale of interest in Glass Mountain	—			—		292,117			—			292,117
Transaction with an unconsolidated entity (Note 13)	—			—		(6,424		)	—			(6,424		)
Investments in unconsolidated entities	—			—		(21,461		)	—			(21,461		)
Distributions of capital from unconsolidated entities	—			—		11,710			—			11,710
Repayments on loan for natural gas liquids facility	—			—		7,425			—			7,425
Loan to affiliate	—			—		(1,460		)	—			(1,460		)
Repayments on loan to affiliate	—			—		4,160			—			4,160
Other (Note 14)	—			—		20,000			—			20,000
Net cash provided by (used in) investing activities	—			—		106,865			(1,813		)	105,052
FINANCING ACTIVITIES:
Proceeds from borrowings under Revolving Credit Facility	—			—		1,674,500			—			1,674,500
Payments on Revolving Credit Facility	—			—		(1,349,500		)	—			(1,349,500		)
Repayment and repurchase of senior secured and senior unsecured notes	(415,568		)	—		—			—			(415,568		)
Payments on other long-term debt	—			—		(3,971		)	(390		)	(4,361		)
Debt issuance costs	(693		)	—		(1,804		)	—			(2,497		)
Contributions from noncontrolling interest owners, net	—			—		—			23			23
Distributions to general and common unit partners and preferred unitholders	(166,589		)	—		—			—			(166,589		)
Distributions to noncontrolling interest owners	—			—		—			(3,082		)	(3,082		)
Proceeds from sale of preferred units, net of offering costs	202,731			—		—			—			202,731
Repurchase of warrants	(10,549		)	—		—			—			(10,549		)
Common unit repurchases and cancellations	(15,608		)	—		—			—			(15,608		)
Payments for settlement and early extinguishment of liabilities	—			—		(2,408		)	—			(2,408		)
Net changes in advances with consolidated entities	1			—		31,910			(31,911		)	—
Net cash (used in) provided by financing activities	(406,275		)	—		348,727			(35,360		)	(92,908		)
Net increase (decrease) in cash and cash equivalents	8,737			—		8,276			(808		)	16,205
Cash and cash equivalents, beginning of period	6,257			—		2,903			3,104			12,264
Cash and cash equivalents, end of period	$	14,994		$	—	$	11,179		$	2,296		$	28,469

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statement of Cash Flows

(in Thousands)



	Nine Months Ended December 31, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash used in operating activities	$	(48,850	)	$	—	$	(63,850	)	$	(2,872	)	$	(115,572	)
INVESTING ACTIVITIES:
Capital expenditures	—			—		(257,734		)	(6,846		)	(264,580		)
Acquisitions, net of cash acquired	—			—		(116,153		)	(11,360		)	(127,513		)
Cash flows from settlements of commodity derivatives	—			—		(82,815		)	—			(82,815		)
Proceeds from sales of assets	—			—		14,136			59			14,195
Proceeds from sale of TLP common units	—			—		112,370			—			112,370
Proceeds from sale of Grassland	—			—		—			22,000			22,000
Distributions of capital from unconsolidated entities	—			—		7,608			—			7,608
Repayments on loan for natural gas liquids facility	—			—		6,585			—			6,585
Loan to affiliate	—			—		(2,700		)	—			(2,700		)
Repayments on loan to affiliate	—			—		655			—			655
Payment to terminate development agreement	—			—		(16,875		)	—			(16,875		)
Net cash (used in) provided by investing activities	—			—		(334,923		)	3,853			(331,070		)
FINANCING ACTIVITIES:
Proceeds from borrowings under Revolving Credit Facility	—			—		1,176,000			—			1,176,000
Payments on Revolving Credit Facility	—			—		(1,510,500		)	—			(1,510,500		)
Issuance of senior unsecured notes	700,000			—		—			—			700,000
Repurchase of senior unsecured notes	(15,129		)	—		—			—			(15,129		)
Payments on other long-term debt	—			—		(6,359		)	(190		)	(6,549		)
Debt issuance costs	(12,536		)	—		(72		)	—			(12,608		)
Contributions from general partner	59			—		—			—			59
Contributions from noncontrolling interest owners, net	—			—		—			639			639
Distributions to general and common unit partners and preferred unitholders	(132,135		)	—		—			—			(132,135		)
Distributions to noncontrolling interest owners	—			—		—			(3,292		)	(3,292		)
Proceeds from sale of preferred units, net of offering costs	234,989			—		—			—			234,989
Proceeds from sale of common units, net of offering costs	43,896			—		—			—			43,896
Payments for settlement and early extinguishment of liabilities	—			—		(27,977		)	—			(27,977		)
Net changes in advances with consolidated entities	(772,232		)	—		769,955			2,277			—
Net cash provided by (used in) financing activities	46,912			—		401,047			(566		)	447,393
Net (decrease) increase in cash and cash equivalents	(1,938		)	—		2,274			415			751
Cash and cash equivalents, beginning of period	25,749			—		784			1,643			28,176
Cash and cash equivalents, end of period	$	23,811		$	—	$	3,058		$	2,058		$	28,927

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

The following is a discussion of NGL Energy Partners LP’s (“we,” “us,” “our,” or the “Partnership”) financial condition and results of operations as of and for the three months and nine months ended December 31, 2017. The discussion should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q (“Quarterly Report”), as well as Management’s Discussion and Analysis of Financial Condition and Results of Operations and the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2017 (“Annual Report”) filed with the Securities and Exchange Commission on May 26, 2017.

Overview

We are a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At December 31, 2017, our operations include:


•	Our Crude Oil Logistics segment purchases crude oil from producers and transports it to refineries or for resale at pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs, and provides terminaling, trucking, marine and pipeline transportation services through its owned assets.


•	Our Water Solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production and for the disposal of solids such as tank bottoms and drilling fluids and performs truck and frac tank washouts. In addition, our Water Solutions segment sells the recovered hydrocarbons that result from performing these services.


•	Our Liquids segment supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada using its leased underground storage and fleet of leased railcars, markets regionally through its 21 owned terminals throughout the United States, and provides terminaling and storage services at its salt dome storage facility in Utah.


•	Our Retail Propane segment sells propane, distillates, equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 30 states and the District of Columbia.


•	Our Refined Products and Renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations, purchases refined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedules them for delivery at various locations throughout the country.

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Consolidated Results of Operations

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



	Three Months Ended December 31,						Nine Months Ended December 31,
	2017			2016			2017			2016
	(in thousands)
Total revenues	$	4,463,263		$	3,406,641		$	12,168,158		$	9,174,149
Total cost of sales	4,272,808			3,228,022			11,685,637			8,723,192
Operating expenses	84,846			76,981			237,285			225,408
General and administrative expense	29,218			18,280			77,689			88,077
Depreciation and amortization	63,340			60,767			192,427			160,276
(Gain) loss on disposal or impairment of assets, net	(111,480		)	34			(11,242		)	(203,433		)
Revaluation of liabilities	—			—			5,600			—
Operating income (loss)	124,531			22,557			(19,238		)	180,629
Equity in earnings of unconsolidated entities	3,426			1,279			7,270			1,726
Revaluation of investments	—			—			—			(14,365		)
Interest expense	(51,790		)	(41,436		)	(151,249		)	(105,316		)
(Loss) gain on early extinguishment of liabilities, net	(21,141		)	—			(22,479		)	30,890
Other income, net	2,107			20,007			6,113			25,860
Income (loss) before income taxes	57,133			2,407			(179,583		)	119,424
Income tax expense	(364		)	(1,114		)	(934		)	(2,036		)
Net income (loss)	56,769			1,293			(180,517		)	117,388
Less: Net income attributable to noncontrolling interests	(89		)	(317		)	(221		)	(6,091		)
Less: Net (income) loss attributable to redeemable noncontrolling interests	(424		)	—			261			—
Net income (loss) attributable to NGL Energy Partners LP	56,256			976			(180,477		)	111,297
Less: Distributions to preferred unitholders	(16,219		)	(8,906		)	(42,001		)	(20,958		)
Less: Net (income) loss allocated to general partner	(73		)	(22		)	121			(180		)
Less: Repurchase of warrants	—			—			(349		)	—
Net income (loss) allocated to common unitholders	$	39,964		$	(7,952	)	$	(222,706	)	$	90,159

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, disposals and other transactions. Our results of operations for the three months and nine months ended December 31, 2017 are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2018. See the detailed discussion of items affecting operating income (loss) by segment below.

Recent Developments

Repurchases of Senior Secured Notes

In December 2017, we paid $195.0 million in aggregate to pay a semi-annual principal installment payment and repurchase all of the remaining outstanding Senior Secured Notes. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Repurchases of Senior Unsecured Notes

During the three months ended December 31, 2017, we repurchased $17.0 million of the 7.50% senior notes due 2023 (the “2023 Notes”) and $71.8 million of the 6.125% senior notes due 2025 (the “2025 Notes”). See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

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Common Unit Repurchase Program

Tax Cuts and Jobs Act of 2017

We have certain taxable corporate subsidiaries 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. In addition, as of December 31, 2017, we do not have any deferred tax assets or liabilities. Any future deferred tax assets or liabilities will be valued based on the new corporate tax rate under the Act.

Amendment to Credit Agreement

Acquisitions

As discussed below, we completed numerous acquisitions during the fiscal year ended March 31, 2017 and the nine months ended December 31, 2017. These acquisitions impact the comparability of our results of operations between our current and prior fiscal years.

During the nine months ended December 31, 2017, in our Water Solutions segment, we acquired the remaining 50% ownership interest in NGL Solids Solutions, LLC, and in our Retail Propane segment, we acquired six retail propane businesses and certain assets from an equity method investee. See Note 4 and Note 13 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

During the fiscal year ended March 31, 2017, we acquired:


•	three water solutions facilities;


•	the remaining 25% ownership interest in three water solutions facilities;


•	an additional 24.5% interest in an existing produced water pipeline company;


•	the remaining 65% ownership interest in Grassland Water Solutions, LLC (“Grassland”), in which we subsequently sold 100% of our interest;


•	four retail propane businesses; and


•	certain natural gas liquids facilities.

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Dispositions

Potential Sale of a Portion of Retail Propane Business

Sale of Interest in Glass Mountain Pipeline, LLC

On December 22, 2017, we sold our previously held 50% interest in Glass Mountain Pipeline, LLC (“Glass Mountain”) for net proceeds of $292.1 million and recorded a gain on disposal of $108.6 million during the three months ended December 31, 2017. See Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

As this sale transaction does not represent a strategic shift that will have a major effect on our operations or financial results, operations related to this portion of our Crude Oil Logistics segment have not be classified as discontinued operations.

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Segment Operating Results for the Three Months Ended December 31, 2017 and 2016

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,
	2017			2016			Change
	(in thousands, except per barrel amounts)
Revenues:
Crude oil sales	$	556,001		$	366,569		$	189,432
Crude oil transportation and other	33,017			20,914			12,103
Total revenues (1)	589,018			387,483			201,535
Expenses:
Cost of sales	556,882			363,416			193,466
Operating expenses	11,712			10,591			1,121
General and administrative expenses	1,627			1,481			146
Depreciation and amortization expense	20,092			16,503			3,589
(Gain) loss on disposal or impairment of assets, net	(107,574		)	4,655			(112,229		)
Total expenses	482,739			396,646			86,093
Segment operating income (loss)	$	106,279		$	(9,163	)	$	115,442

Crude oil sold (barrels)	10,006			7,527			2,479
Crude oil transported on owned pipelines (barrels)	9,228			1,610			7,618
Crude oil storage capacity - owned and leased (barrels) (2)	6,362			6,765			(403		)
Crude oil storage capacity leased to third parties (barrels) (2)	2,829			4,398			(1,569		)
Crude oil inventory (barrels) (2)	1,356			2,037			(681		)
Crude oil sold ($/barrel)	$	55.567		$	48.701		$	6.866
Cost per crude oil sold ($/barrel)	$	55.655		$	48.282		$	7.373
Crude oil product margin ($/barrel)	$	(0.088	)	$	0.419		$	(0.507	)


(1)	Revenues include $4.0 million and $1.6 million of intersegment sales during the three months ended December 31, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of December 31, 2017 and December 31, 2016, respectively.

Crude Oil Sales. The increase was due primarily to an increase in crude oil prices and barrels sold during the three months ended December 31, 2017, compared to the three months ended December 31, 2016. This segment continued to be impacted by competition and low margins in the majority of the basins across the United States and we continue to market crude volumes in these basins to support our various pipeline, terminal and transportation assets. Additionally, we bear the cost of certain minimum volume commitments on third-party crude oil pipelines in various basins which are currently not profitable.

Crude Oil Transportation and Other Revenues. The increase was due primarily to our Grand Mesa Pipeline becoming operational on November 1, 2016 which increased revenues by $10.5 million during the three months ended December 31, 2017, compared to the three months ended December 31, 2016. During the three months ended December 31, 2017, approximately 9.2 million barrels of crude oil were transported on the Grand Mesa Pipeline, which averaged approximately 100,000 barrels per day and financial volumes averaged approximately 106,000 barrels per day. Higher revenues in our trucking and barge operations during the three months ended December 31, 2017 were due primarily to increased demand for transportation services, compared to the three months ended December 31, 2016, and were partially offset by the flattening of the contango curve for crude oil (a condition in which forward crude oil prices are greater than spot prices) during the three months ended December 31, 2017, compared to the three months ended December 31, 2016.

Cost of Sales. The increase was due primarily to an increase in crude oil prices during the three months ended December 31, 2017, compared to the three months ended December 31, 2016. Our cost of sales during the three months ended

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December 31, 2017 was increased by $4.7 million of net realized losses on derivatives and $1.0 million of net unrealized losses on derivatives. Our cost of sales during the three months ended December 31, 2016 was increased by $3.4 million of net realized losses on derivatives and $0.7 million of net unrealized losses on derivatives.

Operating and General and Administrative Expenses. The increase was due primarily to our Grand Mesa Pipeline becoming operational on November 1, 2016 which increased expenses by $1.8 million during the three months ended December 31, 2017, compared to the three months ended December 31, 2016. This increase was partially offset by lower repair and maintenance expense related to having a newer fleet of barges and a smaller fleet of trucks, as well as the timing of repairs, and lower property taxes due to decreased inventory.

Depreciation and Amortization Expense. The increase was due primarily to our Grand Mesa Pipeline becoming operational on November 1, 2016 which increased depreciation and amortization expense by $2.6 million during the three months ended December 31, 2017, compared to the three months ended December 31, 2016. Also contributing to the increase was higher depreciation expense related to other capital projects being placed into service.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the three months ended December 31, 2017, we recorded a gain of $108.6 million on the sale of our previously held 50% interest in Glass Mountain (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report). In addition, we recorded a net loss of $1.0 million on the sales of excess pipe and certain other assets. During the three months ended December 31, 2016, we recorded a net loss of $4.7 million on the sales of certain assets.

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Water Solutions

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



	Three Months Ended December 31,
	2017			2016			Change
	(in thousands, except per barrel and per day amounts)
Revenues:
Service fees	$	41,045		$	28,268		$	12,777
Recovered hydrocarbons	17,021			6,387			10,634
Other revenues	5,958			5,704			254
Total revenues	64,024			40,359			23,665
Expenses:
Cost of sales-derivative loss (gain)	9,481			(238		)	9,719
Cost of sales-other	711			715			(4		)
Operating expenses	27,041			21,728			5,313
General and administrative expenses	649			579			70
Depreciation and amortization expense	24,586			27,150			(2,564		)
Loss on disposal or impairment of assets, net	2,929			2,323			606
Total expenses	65,397			52,257			13,140
Segment operating loss	$	(1,373	)	$	(11,898	)	$	10,525

Wastewater processed (barrels per day)
Eagle Ford Basin	255,634			203,349			52,285
Permian Basin	334,556			208,495			126,061
DJ Basin	121,061			67,560			53,501
Other Basins	78,144			36,778			41,366
Total	789,395			516,182			273,213
Solids processed (barrels per day)	6,095			2,624			3,471
Skim oil sold (barrels per day)	3,623			1,597			2,026
Service fees for wastewater processed ($/barrel)	$	0.57		$	0.60		$	(0.03	)
Recovered hydrocarbons for wastewater processed ($/barrel)	$	0.23		$	0.13		$	0.10
Operating expenses for wastewater processed ($/barrel)	$	0.37		$	0.46		$	(0.09	)

Service Fee Revenues. The increase was due primarily to an increase in the volume of wastewater processed at existing facilities, partially offset with higher volumes in areas with lower fees. We continue to benefit from the increased rig counts as compared to the prior year in the basins in which we operate, particularly in the Permian Basin.

Recovered Hydrocarbon Revenues. The increase was due primarily to an increase in the volume of wastewater processed, an increase in the amount of hydrocarbons per barrel of wastewater processed and an increase in crude oil prices.

Other Revenues. Other revenues primarily include solids disposal revenues and water pipeline revenues, both of which increased during the three months ended December 31, 2017 due to increased volumes. These increases were partially offset by a decrease in freshwater revenues due to the sale of Grassland in November 2016 (see below discussion of the loss on the sale of Grassland).

Cost of Sales-Derivatives. 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 and selling the skim oil. Our cost of sales during the three months ended December 31, 2017 included $8.5 million of net unrealized losses on derivatives and $1.0 million of net realized losses on derivatives. Our cost of sales during the three months ended December 31, 2016 included $1.3 million of net unrealized gains on derivatives and $1.1 million of net realized losses on derivatives.

Cost of Sales-Other. Cost of sales-other for the current quarter was consistent with the prior year quarter.

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Operating and General and Administrative Expenses. The increase was due primarily to higher costs of operations of water disposal wells due to higher volumes processed, partially offset by cost reduction efforts.

Depreciation and Amortization Expense. The decrease was due primarily to certain intangible assets being fully amortized during the fiscal year ended March 31, 2017, partially offset by acquisitions and developed facilities.

Loss on Disposal or Impairment of Assets, Net. During the three months ended December 31, 2017, we recorded a net loss of $2.9 million on the disposals of certain assets. During the three months ended December 31, 2016, we recorded a net loss of $2.3 million on the sale of Grassland and the sales of certain other 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,
	2017			2016		Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	403,236		$	260,562	$	142,674
Cost of sales	388,861			242,949		145,912
Product margin	14,375			17,613		(3,238		)

Butane sales:
Revenues (1)	228,535			146,514		82,021
Cost of sales	215,588			135,246		80,342
Product margin	12,947			11,268		1,679

Other product sales:
Revenues (1)	123,677			89,225		34,452
Cost of sales	118,050			84,071		33,979
Product margin	5,627			5,154		473

Other revenues:
Revenues (1)	6,166			7,704		(1,538		)
Cost of sales	772			2,410		(1,638		)
Product margin	5,394			5,294		100

Expenses:
Operating expenses	8,659			8,846		(187		)
General and administrative expenses	1,361			1,217		144
Depreciation and amortization expense	6,247			4,441		1,806
(Gain) loss on disposal or impairment of assets, net	(214		)	60		(274		)
Total expenses	16,053			14,564		1,489
Segment operating income	$	22,290		$	24,765	$	(2,475	)

Liquids storage capacity - owned and leased (gallons) (2)	453,971			358,537		95,434

Propane sold (gallons)	399,211			386,854		12,357
Propane sold ($/gallon)	$	1.010		$	0.674	$	0.336
Cost per propane sold ($/gallon)	$	0.974		$	0.628	$	0.346
Propane product margin ($/gallon)	$	0.036		$	0.046	$	(0.010	)
Propane inventory (gallons) (2)	130,940			135,582		(4,642		)
Propane storage capacity leased to third parties (gallons) (2)	33,495			33,264		231

Butane sold (gallons)	191,504			149,403		42,101
Butane sold ($/gallon)	$	1.193		$	0.981	$	0.212
Cost per butane sold ($/gallon)	$	1.126		$	0.905	$	0.221
Butane product margin ($/gallon)	$	0.067		$	0.076	$	(0.009	)
Butane inventory (gallons) (2)	41,941			22,261		19,680
Butane storage capacity leased to third parties (gallons) (2)	80,346			72,540		7,806

Other products sold (gallons)	104,136			89,974		14,162
Other products sold ($/gallon)	$	1.188		$	0.992	$	0.196
Cost per other products sold ($/gallon)	$	1.134		$	0.934	$	0.200
Other products product margin ($/gallon)	$	0.054		$	0.058	$	(0.004	)
Other products inventory (gallons) (2)	9,616			6,887		2,729


(1)	Revenues include $52.6 million and $33.7 million of intersegment sales during the three months ended December 31, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of December 31, 2017 and December 31, 2016, respectively.

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Propane Sales. The increase in revenues was due to increased sales volumes and higher commodity prices.

Our cost of wholesale propane sales was increased by $4.2 million of net unrealized losses on derivatives and reduced by $5.8 million of net realized gains on derivatives during the three months ended December 31, 2017. During the three months ended December 31, 2016, our cost of wholesale propane sales was reduced by $0.7 million of net unrealized gains on derivatives and less than $0.1 million of net realized gains on derivatives.

Propane margins weakened during the quarter due to increased fixed-price contract deliveries against rising inventory values.

Butane Sales. The increase in revenues and cost of sales was due primarily to higher commodity prices and increased volumes sold due to increased demand in the market place.

Our cost of butane sales during the three months ended December 31, 2017 was reduced by $12.6 million of net unrealized gains on derivatives, compared to a decrease of $2.6 million of net unrealized gains on derivatives during the three months ended December 31, 2016. Additionally, our cost of butane sales was increased by $16.9 million of net realized losses on derivatives and $6.4 million of net realized losses on derivatives during the three months ended December 31, 2017 and 2016, respectively.

Product margins per gallon of butane were lower during the three months ended December 31, 2017 than during the three months ended December 31, 2016 due to higher commodity costs and storage costs due to the oversupplied markets.

Other Products Sales. The increase in the volume of other products sold was due primarily to a new long-term marketing agreement. Volumes have also increased with the addition of the new Port Hudson and Kingfisher terminals.

Our cost of sales of other products was reduced by $0.2 million of net unrealized gains on derivatives and increased by net realized losses on derivatives of $0.1 million during the three months ended December 31, 2017. Our cost of sales of other products during the three months ended December 31, 2016 was reduced by $0.1 million of net unrealized gains on derivatives and $0.4 million of net realized gains on derivatives.

Product margins during the three months ended December 31, 2017 were higher due primarily to product margins at the Kingfisher terminal.

Other Revenues. This revenue includes storage, terminaling and transportation services income. The decrease was due primarily to a decline in hauling activity and lower storage service income.

Operating and General and Administrative Expenses. Expenses for the current quarter were consistent with the prior year quarter.

Depreciation and Amortization Expense. The increase was due primarily to additional assets being placed into service as well as the acquisition of two liquids facilities during the previous fiscal year.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the three months ended December 31, 2017, we recorded a net gain of $0.2 million related to the sale of assets. During the three months ended December 31, 2016, we recorded a net loss of $0.1 million related to the retirement of assets.

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Retail Propane

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



	Three Months Ended December 31,
	2017		2016			Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	124,466	$	96,699		$	27,767
Cost of sales	66,368		42,463			23,905
Product margin	58,098		54,236			3,862

Distillate sales:
Revenues (1)	22,806		19,569			3,237
Cost of sales	17,336		14,300			3,036
Product margin	5,470		5,269			201

Other revenues:
Revenues (1)	12,797		12,418			379
Cost of sales	3,783		3,745			38
Product margin	9,014		8,673			341

Expenses:
Operating expenses	33,750		32,279			1,471
General and administrative expenses	2,822		2,810			12
Depreciation and amortization expense	11,130		11,379			(249		)
Loss (gain) on disposal or impairment of assets, net	908		(62		)	970
Total expenses	48,610		46,406			2,204
Segment operating income	$	23,972	$	21,772		$	2,200

Propane sold (gallons)	62,058		56,572			5,486
Propane sold ($/gallon)	$	2.006	$	1.709		$	0.297
Cost per propane sold ($/gallon)	$	1.069	$	0.751		$	0.318
Propane product margin ($/gallon)	$	0.937	$	0.958		$	(0.021	)
Propane inventory (gallons) (2)	6,760		10,708			(3,948		)

Distillates sold (gallons)	9,381		9,139			242
Distillates sold ($/gallon)	$	2.431	$	2.141		$	0.290
Cost per distillates sold ($/gallon)	$	1.848	$	1.565		$	0.283
Distillates product margin ($/gallon)	$	0.583	$	0.576		$	0.007
Distillates inventory (gallons) (2)	2,618		2,457			161


(1)	Revenues include less than $0.1 million of intersegment sales during the three months ended December 31, 2017 that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of December 31, 2017 and December 31, 2016, respectively, and does not include the inventory for the portion of the Retail Propane segment that has been classified as held for sale as of December 31, 2017 (see Note 14 to our unaudited condensed consolidated financial statements included in this Quarterly Report).

Revenues. Propane revenues and volumes increased due to acquisitions in the current year and prior year and an increase in commodity prices. Distillates revenues and volumes increased due to acquisitions and an increase in commodity prices.

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Cost of Sales. The increase in propane cost was due primarily to increased volumes as a result of the current and prior year acquisitions as well as an increase in commodity prices. The distillates cost increase was due primarily to an increase in volumes resulting from acquisitions as well as an increase in commodity prices.

Operating and General and Administrative Expenses. The increase was due primarily to increased operating expenses and integration costs from acquisitions of four retail propane businesses during the previous fiscal year and six retail propane businesses and the acquisition of certain assets from an equity method investee in the current year.

Depreciation and Amortization Expense. The decrease was primarily due to no depreciation or amortization expense in December 2017 for the portion of the Retail Propane segment that was classified as held for sale. This was offset by increased expenses as a result of the acquisition of four retail propane businesses during the previous fiscal year and the acquisitions made during the current year.

Loss (Gain) on Disposal or Impairment of Assets, Net. Amount represents expenses related to the potential sale of a portion of the Retail Propane segment as well as gains and losses on the sales of surplus assets.

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Refined Products and Renewables

The following table summarizes the operating results of our Refined Products and Renewables segment for the periods indicated:



	Three Months Ended December 31,
	2017			2016			Change
	(in thousands, except per barrel amounts)
Refined products sales:
Revenues (1)	$	2,845,482		$	2,258,317		$	587,165
Cost of sales	2,862,533			2,254,283			608,250
Product (loss) margin	(17,051		)	4,034			(21,085		)

Renewables sales:
Revenues	99,436			123,065			(23,629		)
Cost of sales	89,045			120,041			(30,996		)
Product margin	10,391			3,024			7,367

Service fee revenues	94			50			44

Expenses:
Operating expenses	3,343			3,198			145
General and administrative expenses	2,088			2,238			(150		)
Depreciation and amortization expense	323			404			(81		)
Gain on disposal or impairment of assets, net	(7,529		)	(6,941		)	(588		)
Total income	(1,775		)	(1,101		)	(674		)
Segment operating (loss) income	$	(4,791	)	$	8,209		$	(13,000	)

Gasoline sold (barrels)	22,902			22,227			675
Diesel sold (barrels)	15,004			13,215			1,789
Ethanol sold (barrels)	900			1,125			(225		)
Biodiesel sold (barrels)	477			733			(256		)
Refined products and renewables storage capacity - leased (barrels) (2)	9,046			7,794			1,252
Refined products and renewables storage capacity sub-leased to third parties (barrels) (2)	1,068			938			130
Gasoline inventory (barrels) (2)	3,007			2,627			380
Diesel inventory (barrels) (2)	1,605			2,738			(1,133		)
Ethanol inventory (barrels) (2)	684			502			182
Biodiesel inventory (barrels) (2)	153			501			(348		)
Refined products sold ($/barrel)	$	75.067		$	63.719		$	11.348
Cost per refined products sold ($/barrel)	$	75.517		$	63.605		$	11.912
Refined products product (loss) margin ($/barrel)	$	(0.450	)	$	0.114		$	(0.564	)
Renewable products sold ($/barrel)	$	72.212		$	66.235		$	5.977
Cost per renewable products sold ($/barrel)	$	64.666		$	64.608		$	0.058
Renewable products product margin ($/barrel)	$	7.546		$	1.627		$	5.919


(1)	Revenues include $0.1 million and $0.1 million of intersegment sales during the three months ended December 31, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of December 31, 2017 and December 31, 2016, respectively.

Refined Products Revenues and Cost of Sales. The increases in revenues and cost of sales were due to an increase in refined products prices and increased volumes. The decrease in margin was due primarily to the decrease in line space values

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on the Colonial Pipeline during the three months ended December 31, 2017, as compared to the same period in the prior year. The average value of line space was approximately $0.006 per gallon for the three months ended December 31, 2017, compared to an average value of approximately $0.032 per gallon for the three months ended December 31, 2016. In addition, margins for both the three months ended December 31, 2017 and 2016 were negatively impacted by losses of $40.0 million and $50.7 million, respectively, from our risk management activities. These losses were primarily a result of increasing future prices.

Renewables Revenues and Cost of Sales. The decreases in revenues and cost of sales were due primarily to decreased volumes, partially offset by an increase in renewables prices. The margin was higher during the three months ended December 31, 2017 due primarily to favorable biodiesel margins resulting from the biodiesel tax credit being reinstated in February 2018 for the 2017 calendar year, offset by losses on risk management transactions due to the weakness in the price of renewable identification numbers and increasing future prices. Losses from risk management activities were $7.2 million for the three months ended December 31, 2017.

Service Fee Revenues, Operating Expenses, General and Administrative Expenses. These items for the current quarter were consistent with the prior year quarter.

Depreciation and Amortization Expense. The decrease was due primarily to certain assets being fully depreciated during the fiscal year ended March 31, 2017.

Gain on Disposal or Impairment of Assets, Net. During the three months ended December 31, 2017, we recorded $7.5 million of the deferred gain from the sale of the general partner interest in TransMontaigne Partners L.P. (“TLP”) in February 2016 (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion).

During the three months ended December 31, 2016, we recorded:


•	$7.5 million of the deferred gain from the sale of the general partner interest in TLP (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion); and


•	a loss of $0.6 million on the sales of certain assets.

Corporate and Other

The operating loss within “Corporate and Other” includes the following components for the periods indicated:



	Three Months Ended December 31,
	2017			2016			Change
	(in thousands)
Other revenues
Revenues	$	289		$	164		$	125
Cost of sales	117			77			40
Margin	172			87			85

Expenses:
Operating expenses	385			371			14
General and administrative expenses	20,671			9,955			10,716
Depreciation and amortization expense	962			890			72
Gain on disposal or impairment of assets, net	—			(1		)	1
Total expenses	22,018			11,215			10,803
Operating loss	$	(21,846	)	$	(11,128	)	$	(10,718	)

General and Administrative Expenses. The increase during the three months ended December 31, 2017 was due primarily to an increase in compensation expense as a result of increased incentive compensation and increased legal professional fees. This was offset by lower equity-based compensation expense related to our service and performance awards. In the current year, the number of units granted was significantly less than the number of units that have vested, thus, expense related to new grants has not fully replaced the expense from units that have fully vested during the period.

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Equity in Earnings of Unconsolidated Entities

The increase of $2.1 million during the three months ended December 31, 2017 was due primarily to increased earnings related to our investment in Glass Mountain. On December 22, 2017, we sold our previously held 50% interest in Glass Mountain. See Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Interest Expense

Interest expense includes interest expense on our Revolving Credit Facility and senior notes, amortization of debt issuance costs, letter of credit fees, interest on equipment financing notes, and accretion of interest on non-interest bearing debt obligations. The increase of $10.4 million during the three months ended December 31, 2017 was due primarily to the issuance of $700.0 million of fixed-rate notes during October 2016 and the issuance of $500.0 million of fixed-rate notes during February 2017.

Loss on Early Extinguishment of Liabilities, Net

During the three months ended December 31, 2017, we repurchased a portion of the 2023 Notes and 2025 Notes and all of the remaining outstanding senior secured notes and recorded a net loss on the early extinguishment of these notes of $21.1 million. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Other Income, Net

The following table summarizes the components of other income, net for the periods indicated:



	Three Months Ended December 31,
	2017			2016
	(in thousands)
Interest income (1)	$	1,787		$	1,921
Crude oil marketing arrangement (2)	(38		)	39
Termination of storage sublease agreement (3)	—			16,205
Other (4)	358			1,842
Other income, net	$	2,107		$	20,007


(1)	Relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party and to a loan receivable from an equity method investee (see Note 2 and Note 13, respectively, to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion).


(2)	Represents another party’s share of the profits and losses generated from a joint crude oil marketing arrangement.

(3)

During the three months ended December 31, 2016, we agreed to terminate a storage sublease agreement that was scheduled to commence in January 2017 and had a term of five years. For terminating this agreement, the counterparty agreed to pay us a specific amount in five equal payments beginning in February 2017 and in January of the next four years and removed any future obligations of the Partnership. As a result, we discounted the future payments and recorded a gain.


(4)	During the three months ended December 31, 2017, this relates primarily to proceeds from a litigation settlement. During the three months ended December 31, 2016, this relates primarily to a gain on insurance settlement from damage to two facilities in our Water Solutions segment and a payment received related to a contract termination.

Income Tax Expense

Income tax expense was $0.4 million during the three months ended December 31, 2017, compared to income tax expense of $1.1 million during the three months ended December 31, 2016. The decrease in income tax expense was due primarily to a lower state franchise tax liability in Texas from a lower tax rate and lower Texas revenues as well as a lower Canadian tax liability from lower income in our taxable corporate subsidiaries in Canada. See Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

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Segment Operating Results for the Nine Months Ended December 31, 2017 and 2016

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,
	2017			2016			Change
	(in thousands, except per barrel amounts)
Revenues:
Crude oil sales	$	1,446,560		$	1,123,169		$	323,391
Crude oil transportation and other	89,318			43,020			46,298
Total revenues (1)	1,535,878			1,166,189			369,689
Expenses:
Cost of sales	1,432,445			1,112,034			320,411
Operating expenses	36,079			29,413			6,666
General and administrative expenses	4,927			4,456			471
Depreciation and amortization expense	61,885			34,496			27,389
(Gain) loss on disposal or impairment of assets, net	(111,290		)	14,617			(125,907		)
Total expenses	1,424,046			1,195,016			229,030
Segment operating income (loss)	$	111,832		$	(28,827	)	$	140,659

Crude oil sold (barrels)	28,588			24,838			3,750
Crude oil transported on owned pipelines (barrels)	24,176			1,610			22,566
Crude oil storage capacity - owned and leased (barrels) (2)	6,362			6,765			(403		)
Crude oil storage capacity leased to third parties (barrels) (2)	2,829			4,398			(1,569		)
Crude oil inventory (barrels) (2)	1,356			2,037			(681		)
Crude oil sold ($/barrel)	$	50.600		$	45.220		$	5.380
Cost per crude oil sold ($/barrel)	$	50.107		$	44.771		$	5.336
Crude oil product margin ($/barrel)	$	0.493		$	0.449		$	0.044


(1)	Revenues include $8.9 million and $4.4 million of intersegment sales during the nine months ended December 31, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of December 31, 2017 and December 31, 2016, respectively.

Crude Oil Sales. The increase was due primarily to an increase in crude oil prices and barrels sold during the nine months ended December 31, 2017, compared to the nine months ended December 31, 2016. This segment continued to be impacted by competition and low margins in the majority of the basins across the United States and we continue to market crude volumes in these basins to support our various pipeline, terminal and transportation assets. Additionally, we bear the cost of certain minimum volume commitments on third-party crude oil pipelines in various basins which are currently not profitable.

Crude Oil Transportation and Other Revenues. The increase was due primarily to our Grand Mesa Pipeline becoming operational on November 1, 2016 which increased revenues by $48.9 million during the nine months ended December 31, 2017, compared to the nine months ended December 31, 2016. During the nine months ended December 31, 2017, approximately 24.2 million barrels of crude oil were transported on the Grand Mesa Pipeline, which averaged approximately 88,000 barrels per day and financial volumes averaged approximately 92,000 barrels per day. Higher revenues in our trucking operations during the nine months ended December 31, 2017 were due primarily to increased demand for transportation services, compared to the nine months ended December 31, 2016, and were partially offset by the flattening of the contango curve for crude oil (a condition in which forward crude oil prices are greater than spot prices) during the nine months ended December 31, 2017, compared to the nine months ended December 31, 2016.

Cost of Sales. The increase was due primarily to an increase in crude oil prices during the nine months ended December 31, 2017, compared to the nine months ended December 31, 2016. Our cost of sales during the nine months ended December 31, 2017 was increased by $2.5 million of net unrealized losses on derivatives and $0.5 million of net realized losses

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on derivatives. Our cost of sales during the nine months ended December 31, 2016 was increased by $8.9 million of net realized losses on derivatives and $1.0 million of net unrealized losses on derivatives.

Operating and General and Administrative Expenses. The increase was due primarily to our Grand Mesa Pipeline becoming operational on November 1, 2016 which increased expenses by $8.6 million during the nine months ended December 31, 2017, compared to the nine months ended December 31, 2016. This increase was partially offset by lower repair and maintenance expense related to having a newer fleet of barges and a smaller fleet of trucks, as well as the timing of repairs, and lower property taxes due to decreased inventory.

Depreciation and Amortization Expense. The increase was due primarily to our Grand Mesa Pipeline becoming operational on November 1, 2016 which increased depreciation and amortization expense by $23.7 million during the nine months ended December 31, 2017, compared to the nine months ended December 31, 2016. Also contributing to the increase was higher depreciation expense related to other capital projects being placed into service.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the nine months ended December 31, 2017, we recorded a gain of $108.6 million on the sale of our previously held 50% interest in Glass Mountain (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report). During the nine months ended December 31, 2017, we recorded a net gain of $2.7 million on the sales of excess pipe and certain other assets. During the nine months ended December 31, 2016, we recorded a net loss of $10.9 million on the sales of certain assets and a loss of $3.7 million due to the write-down of certain other assets.

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Water Solutions

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



	Nine Months Ended December 31,
	2017			2016			Change
	(in thousands, except per barrel and per day amounts)
Revenues:
Service fees	$	109,648		$	82,493		$	27,155
Recovered hydrocarbons	37,427			19,264			18,163
Other revenues	14,948			14,088			860
Total revenues	162,023			115,845			46,178
Expenses:
Cost of sales-derivative loss	11,529			2,449			9,080
Cost of sales-other	1,490			1,422			68
Operating expenses	74,570			62,233			12,337
General and administrative expenses	1,948			1,850			98
Depreciation and amortization expense	73,847			76,713			(2,866		)
Loss (gain) on disposal or impairment of assets, net	3,114			(91,958		)	95,072
Revaluation of liabilities	5,600			—			5,600
Total expenses	172,098			52,709			119,389
Segment operating (loss) income	$	(10,075	)	$	63,136		$	(73,211	)

Wastewater processed (barrels per day)
Eagle Ford Basin	228,698			207,732			20,966
Permian Basin	280,158			182,165			97,993
DJ Basin	114,156			62,495			51,661
Other Basins	66,884			38,199			28,685
Total	689,896			490,591			199,305
Solids processed (barrels per day)	5,357			2,643			2,714
Skim oil sold (barrels per day)	2,923			1,714			1,209
Service fees for wastewater processed ($/barrel)	$	0.58		$	0.61		$	(0.03	)
Recovered hydrocarbons for wastewater processed ($/barrel)	$	0.20		$	0.14		$	0.06
Operating expenses for wastewater processed ($/barrel)	$	0.39		$	0.46		$	(0.07	)

Other Revenues. The increase was due primarily to an increase in volumes for solids disposal and water pipeline businesses. These increases were partially offset by a decrease in freshwater revenues due to the sale of Grassland in November 2016 (see below discussion of the loss on the sale of Grassland).

Cost of Sales-Derivatives. 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 and selling the skim oil. Our cost of sales during the nine months ended December 31, 2017 included $11.5 million of net unrealized losses on derivatives and less than $0.1 million of net realized losses on derivatives. Our cost of sales during the nine months ended December 31, 2016 included $4.6 million of net realized losses on derivatives and $2.1 million of net unrealized gains on derivatives.

Cost of Sales-Other. Cost of sales-other for the current year was consistent with the prior year.

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Depreciation and Amortization Expense. The decrease was due primarily to lower amortization expense from the write-off of an intangible asset during the nine months ended December 31, 2016 as well as certain intangible assets being fully amortized during the fiscal year ended March 31, 2017, partially offset by acquisitions and developed facilities.

Loss (Gain) on Disposal or Impairment of Assets, Net. During the nine months ended December 31, 2017, we recorded a net loss of $4.4 million on the disposals of certain assets, partially offset by a gain of $1.3 million for the termination of a non-compete agreement, which included the carrying value of the non-compete agreement intangible asset that was written off (see Note 7 to our unaudited condensed consolidated financial statements included in this Quarterly Report).

During the nine months ended December 31, 2016, we recorded:


•	an adjustment of $124.7 million of the previously recorded $380.2 million estimated goodwill impairment charge recorded during the three months ended March 31, 2016;


•	a write-off of $5.2 million related to the value of an indefinite-lived trade name intangible asset in conjunction with finalizing our goodwill impairment analysis in June 2016;


•	a loss of $22.7 million related to the termination of a development agreement in June 2016, which included the carrying value of the development agreement asset that was written off;


•	a net loss of $3.1 million on the sale of Grassland and the sales of certain other assets; and


•	an impairment charge of $1.7 million to write down a loan receivable in June 2016.

Revaluation of Liabilities. The revaluation of liabilities represents the change in the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations during the fiscal year ended March 31, 2017. The increase in the expense during the nine months ended December 31, 2017 was due primarily to higher actual and expected production from new customers, resulting in an increase to the expected future royalty payment.

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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,
	2017			2016		Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	733,684		$	458,646	$	275,038
Cost of sales	703,135			430,775		272,360
Product margin	30,549			27,871		2,678

Butane sales:
Revenues (1)	408,312			267,769		140,543
Cost of sales	406,835			248,082		158,753
Product margin	1,477			19,687		(18,210		)

Other product sales:
Revenues (1)	310,389			217,405		92,984
Cost of sales	295,590			201,457		94,133
Product margin	14,799			15,948		(1,149		)

Other revenues:
Revenues (1)	16,106			22,926		(6,820		)
Cost of sales	2,294			8,069		(5,775		)
Product margin	13,812			14,857		(1,045		)

Expenses:
Operating expenses	25,011			28,386		(3,375		)
General and administrative expenses	3,982			3,461		521
Depreciation and amortization expense	18,718			13,315		5,403
Loss on disposal or impairment of assets, net	117,515			109		117,406
Total expenses	165,226			45,271		119,955
Segment operating (loss) income	$	(104,589	)	$	33,092	$	(137,681	)

Liquids storage capacity - owned and leased (gallons) (2)	453,971			358,537		95,434

Propane sold (gallons)	881,719			813,490		68,229
Propane sold ($/gallon)	$	0.832		$	0.564	$	0.268
Cost per propane sold ($/gallon)	$	0.797		$	0.530	$	0.267
Propane product margin ($/gallon)	$	0.035		$	0.034	$	0.001
Propane inventory (gallons) (2)	130,940			135,582		(4,642		)
Propane storage capacity leased to third parties (gallons) (2)	33,495			33,264		231

Butane sold (gallons)	408,440			347,858		60,582
Butane sold ($/gallon)	$	1.000		$	0.770	$	0.230
Cost per butane sold ($/gallon)	$	0.996		$	0.713	$	0.283
Butane product margin ($/gallon)	$	0.004		$	0.057	$	(0.053	)
Butane inventory (gallons) (2)	41,941			22,261		19,680
Butane storage capacity leased to third parties (gallons) (2)	80,346			72,540		7,806

Other products sold (gallons)	296,756			256,451		40,305
Other products sold ($/gallon)	$	1.046		$	0.848	$	0.198
Cost per other products sold ($/gallon)	$	0.996		$	0.786	$	0.210
Other products product margin ($/gallon)	$	0.050		$	0.062	$	(0.012	)
Other products inventory (gallons) (2)	9,616			6,887		2,729


(1)	Revenues include $88.5 million and $57.2 million of intersegment sales during the nine months ended December 31, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of December 31, 2017 and December 31, 2016, respectively.

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Propane Sales. The increase in revenues was due primarily to an increase in commodity prices. The propane volume increase was due primarily to a new long-term marketing agreement.

Our cost of wholesale propane sales was reduced by $1.2 million of net unrealized gains on derivatives and $5.9 million of net realized gains on derivatives during the nine months ended December 31, 2017. During the nine months ended December 31, 2016, our cost of wholesale propane sales was reduced by $1.7 million of net unrealized gains on derivatives and $0.5 million of net realized gains on derivatives. The increase in cost of sales was due to an increase in commodity prices.

Product margins per gallon of propane sold were higher during the nine months ended December 31, 2017 than during the nine months ended December 31, 2016. Product margins have improved due to the increase in commodity prices outpacing rising inventory values.

Butane Sales. The increase in revenues and cost of sales was due primarily to higher commodity prices. Volumes increased due to favorable market conditions.

Our cost of butane sales during the nine months ended December 31, 2017 was increased by $3.9 million of net unrealized losses on derivatives, compared to an increase of $2.7 million of net unrealized losses on derivatives during the nine months ended December 31, 2016. Additionally, our cost of butane sales was increased by $16.1 million of net realized losses on derivatives and $5.4 million of net realized losses on derivatives during the nine months ended December 31, 2017 and 2016, respectively, due to the steady increase in commodity prices beginning in July 2017.

Product margins per gallon of butane sold were lower during the nine months ended December 31, 2017 than during the nine months ended December 31, 2016 due primarily to the realized and unrealized losses on derivatives noted above and increased storage and rail costs.

Our cost of sales of other products was increased by less than $0.1 million of net unrealized losses on derivatives and reduced by $0.1 million of net realized gains on derivatives during the nine months ended December 31, 2017. Our cost of sales of other products during the nine months ended December 31, 2016 was reduced by $0.8 million of net unrealized gains on derivatives and $0.6 million of net realized gains on derivatives.

Product margins during the nine months ended December 31, 2017 were lower due primarily to an increase in unrecovered railcar fleet costs.

Other Revenues. This revenue includes storage, terminaling and transportation services income. The decrease was due primarily to transportation services and increased storage capacity available in the market.

Operating and General and Administrative Expenses. The decrease was due primarily to lower incentive compensation expense due to decreased earnings.

Depreciation and Amortization Expense. The increase was due primarily to the acquisition of two liquids facilities during the previous fiscal year.

Loss on Disposal or Impairment of Assets, Net. During the nine months ended December 31, 2017, we recorded a goodwill impairment charge of $116.9 million due to the decreased demand for natural gas liquid storage and resulting decline in revenues and earnings as compared to actual and projected results of prior and future periods (see Note 6 to our unaudited condensed consolidated financial statements included in this Quarterly Report). During the nine months ended December 31, 2017 and 2016, we recorded a net loss of $0.6 million and $0.1 million, respectively, related to the retirement of assets.

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Retail Propane

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



	Nine Months Ended December 31,
	2017		2016			Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	221,102	$	174,510		$	46,592
Cost of sales	108,706		70,564			38,142
Product margin	112,396		103,946			8,450

Distillate sales:
Revenues (1)	39,037		35,613			3,424
Cost of sales	29,741		26,244			3,497
Product margin	9,296		9,369			(73		)

Other revenues:
Revenues (1)	31,733		30,056			1,677
Cost of sales	9,996		9,211			785
Product margin	21,737		20,845			892

Expenses:
Operating expenses	90,592		84,628			5,964
General and administrative expenses	7,750		7,304			446
Depreciation and amortization expense	34,205		31,771			2,434
Loss (gain) on disposal or impairment of assets, net	2,004		(96		)	2,100
Total expenses	134,551		123,607			10,944
Segment operating income	$	8,878	$	10,553		$	(1,675	)

Propane sold (gallons)	117,488		105,933			11,555
Propane sold ($/gallon)	$	1.882	$	1.647		$	0.235
Cost per propane sold ($/gallon)	$	0.925	$	0.666		$	0.259
Propane product margin ($/gallon)	$	0.957	$	0.981		$	(0.024	)
Propane inventory (gallons) (2)	6,760		10,708			(3,948		)

Distillates sold (gallons)	17,088		17,505			(417		)
Distillates sold ($/gallon)	$	2.284	$	2.034		$	0.250
Cost per distillates sold ($/gallon)	$	1.740	$	1.499		$	0.241
Distillates product margin ($/gallon)	$	0.544	$	0.535		$	0.009
Distillates inventory (gallons) (2)	2,618		2,457			161


(1)	Revenues include $0.1 million and less than $0.1 million of intersegment sales during the nine months ended December 31, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statement of operations.


(2)	Information is presented as of December 31, 2017 and December 31, 2016, respectively, and does not include the inventory for the portion of the Retail Propane segment that has been classified as held for sale as of December 31, 2017 (see Note 14 to our unaudited condensed consolidated financial statements included in this Quarterly Report).

Revenues. The increase for propane was due to the acquisitions in the prior year and current year as well as increased commodity prices. The increase for distillate revenues was due to higher commodity prices partially offset by lower volumes.

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Cost of Sales. The increase for propane was due primarily to an increase in commodity prices and acquisitions of retail propane businesses. The increase for distillates was due primarily to higher commodity prices partially offset by lower volumes.

Operating and General and Administrative Expenses. The increase was due primarily to increased operating expense from acquisitions of retail propane businesses.

Depreciation and Amortization Expense. The increase was due primarily to acquisitions of retail propane businesses which was partially offset by no depreciation or amortization expense in December 2017 for the portion of the Retail Propane segment that was classified as held for sale.

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Refined Products and Renewables

The following table summarizes the operating results of our Refined Products and Renewables segment for the periods indicated:



	Nine Months Ended December 31,
	2017			2016			Change
	(in thousands, except per barrel amounts)
Refined products sales:
Revenues (1)	$	8,493,357		$	6,409,889		$	2,083,468
Cost of sales	8,478,512			6,353,792			2,124,720
Product margin	14,845			56,097			(41,252		)

Renewables sales:
Revenues	313,366			325,377			(12,011		)
Cost of sales	302,765			320,695			(17,930		)
Product margin	10,601			4,682			5,919

Service fee revenues	262			11,195			(10,933		)

Expenses:
Operating expenses	10,232			19,861			(9,629		)
General and administrative expenses	6,343			7,612			(1,269		)
Depreciation and amortization expense	971			1,237			(266		)
Gain on disposal or impairment of assets, net	(22,585		)	(126,101		)	103,516
Total income	(5,039		)	(97,391		)	92,352
Segment operating income	$	30,747		$	169,365		$	(138,618	)

Gasoline sold (barrels)	77,877			65,278			12,599
Diesel sold (barrels)	43,792			38,415			5,377
Ethanol sold (barrels)	2,892			3,190			(298		)
Biodiesel sold (barrels)	1,672			1,948			(276		)
Refined products and renewables storage capacity - leased (barrels) (2)	9,046			7,794			1,252
Refined products and renewables storage capacity sub-leased to third parties (barrels) (2)	1,068			938			130
Gasoline inventory (barrels) (2)	3,007			2,627			380
Diesel inventory (barrels) (2)	1,605			2,738			(1,133		)
Ethanol inventory (barrels) (2)	684			502			182
Biodiesel inventory (barrels) (2)	153			501			(348		)
Refined products sold ($/barrel)	$	69.807		$	61.816		$	7.991
Cost per refined products sold ($/barrel)	$	69.685		$	61.275		$	8.410
Refined products product margin ($/barrel)	$	0.122		$	0.541		$	(0.419	)
Renewable products sold ($/barrel)	$	68.660		$	63.328		$	5.332
Cost per renewable products sold ($/barrel)	$	66.338		$	62.416		$	3.922
Renewable products product margin ($/barrel)	$	2.322		$	0.912		$	1.410


(1)	Revenues include $0.3 million and $0.3 million of intersegment sales during the nine months ended December 31, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of December 31, 2017 and December 31, 2016, respectively.

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on the Colonial Pipeline during the nine months ended December 31, 2017, as compared to the same period in the prior year. The average value of line space was approximately negative $0.010 per gallon for the nine months ended December 31, 2017, compared to an average value of approximately $0.019 per gallon for the nine months ended December 31, 2016. In addition, margins for both the nine months ended December 31, 2017 and 2016 were negatively impacted by losses of $69.9 million and $86.6 million, respectively, from our risk management activities. These losses were primarily a result of increasing future prices.

Renewables Revenues and Cost of Sales. The decreases in revenues and cost of sales were due primarily to decreased volumes, partially offset by an increase in renewables prices. The margin was higher during the nine months ended December 31, 2017 due primarily to favorable biodiesel margins resulting from the biodiesel tax credit being reinstated in February 2018 for the 2017 calendar year, offset by losses on risk management transactions due to the weakness in the price of renewable identification numbers and increasing future prices. Losses from risk management activities were $2.3 million for the nine months ended December 31, 2017.

Service Fee Revenues, Operating Expenses, General and Administrative Expenses. The decreases were due primarily to the expiration of a transition services agreement in October 2016 related to the sale of all of the TLP units we owned whereby we were reimbursed for certain expenses incurred on behalf of a third party.

Depreciation and Amortization Expense. The decrease was due primarily to certain assets being fully depreciated during the fiscal year ended March 31, 2017.

Gain on Disposal or Impairment of Assets, Net. During the nine months ended December 31, 2017, we recorded $22.6 million of the deferred gain from the sale of the general partner interest in TLP in February 2016 (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion).

During the nine months ended December 31, 2016, we recorded:


•	a $104.1 million gain from the sale of all of the TLP units we owned;


•	$22.6 million of the deferred gain from the sale of the general partner interest in TLP (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion); and


•	a loss of $0.6 million on the sales of certain assets.

Corporate and Other

The operating loss within “Corporate and Other” includes the following components for the periods indicated:



	Nine Months Ended December 31,
	2017			2016			Change
	(in thousands)
Other revenues
Revenues	$	696		$	679		$	17
Cost of sales	311			300			11
Margin	385			379			6

Expenses:
Operating expenses	876			935			(59		)
General and administrative expenses	52,739			63,394			(10,655		)
Depreciation and amortization expense	2,801			2,744			57
Gain on disposal or impairment of assets, net	—			(4		)	4
Total expenses	56,416			67,069			(10,653		)
Operating loss	$	(56,031	)	$	(66,690	)	$	10,659

General and Administrative Expenses. The decrease during the nine months ended December 31, 2017 was primarily due to a decrease in equity-based compensation expense related to service award units, offset by an increase in incentive compensation expense and increased legal professional fees. The expense associated with the service award units was $11.7

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million during the nine months ended December 31, 2017, compared to $32.5 million during the nine months ended December 31, 2016. The decrease in equity-based compensation during the nine months ended December 31, 2017, was due to the following: (i) the cancellation of awards in the prior year which caused an acceleration of expense to be recorded in the prior year, (ii) units that vested in July 2017 were not offset by new grants of service awards during the current year and (iii) during the first quarter of our prior fiscal year, the expense for the service awards was accounted for under the liability method and due to an increase in our unit price during that period, we recorded an increase in equity-based compensation expense. See Note 10 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion of our equity-based compensation awards.

Equity in Earnings of Unconsolidated Entities

The increase of $5.5 million during the nine months ended December 31, 2017 was due primarily to increased earnings related to our investment in Glass Mountain. On December 22, 2017, we sold our previously held 50% interest in Glass Mountain. See Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Revaluation of Investments

As previously reported, on June 3, 2016, we acquired the remaining 65% ownership interest in Grassland. Prior to the completion of this transaction, we accounted for our previously held 35% ownership interest in Grassland using the equity method of accounting. As we owned a controlling interest in Grassland, we revalued our previously held 35% ownership interest to fair value and recorded a loss of $14.9 million. As the amount paid (cash plus the fair value of our previously held ownership interest) was less than the fair value of the assets acquired and liabilities assumed, we recorded a bargain purchase gain of $0.6 million.

Interest Expense

The increase of $45.9 million during the nine months ended December 31, 2017 was due primarily to the issuance of $700.0 million of fixed-rate notes during October 2016 and the issuance of $500.0 million of fixed-rate notes during February 2017. The increase was partially offset by lower interest expense related to our credit facility. The average daily balance of our credit facility was $0.9 billion during the nine months ended December 31, 2017, compared to $1.8 billion during the nine months ended December 31, 2016.

(Loss) Gain on Early Extinguishment of Liabilities, Net

The following table summarizes the components of (loss) gain on early extinguishment of liabilities, net for the periods indicated:



	Nine Months Ended December 31,
	2017			2016
	(in thousands)
Early extinguishment of long-term debt (1)	$	(22,479	)	$	8,614
Release of contingent consideration liabilities (2)	—			22,276
(Loss) gain on early extinguishment of liabilities, net	$	(22,479	)	$	30,890

(1)

During the nine months ended December 31, 2017, this relates to net losses on the early extinguishment of all of the senior secured notes and a portion of the 5.125% senior notes due 2019 (“2019 Notes”), 2023 Notes and 2025 Notes. During the nine months ended December 31, 2016, this relates to gains on the early extinguishment of a portion of the 2019 Notes and 6.875% senior notes due 2021 (“2021 Notes”). See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

(2)

Relates to the release of certain contingent consideration liabilities in conjunction with the termination of a development agreement in June 2016. Also, during the nine months ended December 31, 2016, we acquired certain parcels of land on which one of our water solutions facilities is located and recorded a gain on the release of certain contingent consideration liabilities as the royalty agreement was terminated.

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Other Income, Net

The following table summarizes the components of other income, net for the periods indicated:



	Nine Months Ended December 31,
	2017			2016
	(in thousands)
Interest income (1)	$	5,745		$	6,341
Crude oil marketing arrangement (2)	(48		)	(1,512		)
Termination of storage sublease agreement (3)	—			16,205
Other (4)	416			4,826
Other income, net	$	6,113		$	25,860

(1)

Relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party and to a loan receivable from an equity method investee (see Note 2 and Note 13, respectively, to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion). As previously reported, on June 3, 2016, we acquired the remaining 65% ownership interest in Grassland and all interest income on that receivable has been eliminated in consolidation subsequent to that date.


(2)	Represents another party’s share of the profits and losses generated from a joint crude oil marketing arrangement.

(3)

During the nine months ended December 31, 2016, we agreed to terminate a storage sublease agreement that was scheduled to commence in January 2017 and had a term of five years. For terminating this agreement, the counterparty agreed to pay us a specific amount in five equal payments beginning in February 2017 and in January of the next four years and removed any future obligations of the Partnership. As a result, we discounted the future payments and recorded a gain.

(4)

During the nine months ended December 31, 2017, this relates primarily to proceeds from a litigation settlement. During the nine months ended December 31, 2016, this relates primarily to a distribution from TLP pursuant to the agreement to sell all of the TLP common units we owned in April 2016, a gain on insurance settlement from damage to two facilities in our Water Solutions segment and a payment received related to a contract termination.

Income Tax Expense

Income tax expense was $0.9 million during the nine months ended December 31, 2017, compared to income tax expense of $2.0 million during the nine months ended December 31, 2016. The decrease in income tax expense was due primarily to a lower state franchise tax liability in Texas from a lower tax rate and lower Texas revenues as well as a lower Canadian tax liability from lower income in our taxable corporate subsidiaries in Canada. See Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Noncontrolling Interests - Redeemable and Non-redeemable

Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. The decrease of $6.1 million during the nine months ended December 31, 2017 was due primarily to adjustments related to noncontrolling interests during the nine months ended December 31, 2016.

Non-GAAP Financial Measures

In addition to financial results reported in accordance with accounting principles generally accepted in the United States (“GAAP”), we have provided the non-GAAP financial measures of EBITDA and Adjusted EBITDA. These non-GAAP financial measures are not intended to be a substitute for those reported in accordance with GAAP. These measures may be different from non-GAAP financial measures used by other entities, even when similar terms are used to identify such measures.

We define EBITDA as net income (loss) attributable to NGL Energy Partners LP, plus interest expense, income tax expense (benefit), and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding net unrealized gains and losses on derivatives, lower of cost or market adjustments, gains and losses on disposal or impairment of assets, gains and losses on early extinguishment of liabilities, revaluation of investments, equity-based compensation expense, acquisition expense, revaluation of liabilities and other. We also include in Adjusted EBITDA certain inventory valuation adjustments related to our Refined Products and Renewables segment, as discussed below. EBITDA and Adjusted EBITDA should not be considered alternatives to net income (loss), income (loss) before income taxes, cash flows from operating

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activities, or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information 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, Adjusted EBITDA, or similarly titled measures used by other entities.

Other than for our Refined Products and Renewables segment, for purposes of our Adjusted EBITDA calculation, we make a distinction between realized and unrealized gains and losses on derivatives. During the period when a derivative contract is open, we record changes in the fair value of the derivative as 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. We do not draw such a distinction between realized and unrealized gains and losses on derivatives of our Refined Products and Renewables segment. The primary hedging strategy of our Refined Products and Renewables segment is to hedge against the risk of declines in the value of inventory over the course of the contract cycle, and many of the hedges are six months to one year in duration at inception. The “inventory valuation adjustment” row in the reconciliation table reflects the difference between the market value of the inventory of our Refined Products and Renewables segment at the balance sheet date and its cost. We include this in Adjusted EBITDA because the unrealized gains and losses associated with derivative contracts associated with the inventory of this segment, which are intended primarily to hedge inventory holding risk and are included in net income, also affect Adjusted EBITDA.

The following table reconciles net income (loss) to EBITDA and Adjusted EBITDA:



	Three Months Ended December 31,						Nine Months Ended December 31,
	2017			2016			2017			2016
	(in thousands)
Net income (loss)	$	56,769		$	1,293		$	(180,517	)	$	117,388
Less: Net income attributable to noncontrolling interests	(89		)	(317		)	(221		)	(6,091		)
Less: Net (income) loss attributable to redeemable noncontrolling interests	(424		)	—			261			—
Net income (loss) attributable to NGL Energy Partners LP	56,256			976			(180,477		)	111,297
Interest expense	51,825			41,486			151,391			105,283
Income tax expense	364			1,114			934			2,036
Depreciation and amortization	67,025			64,644			204,514			171,746
EBITDA	175,470			108,220			176,362			390,362
Net unrealized losses (gains) on derivatives	775			(3,957		)	16,851			(737		)
Inventory valuation adjustment (1)	27,786			7,859			6,439			40,552
Lower of cost or market adjustments	(3,907		)	731			5,504			839
(Gain) loss on disposal or impairment of assets, net	(111,479		)	35			(11,241		)	(203,469		)
Loss (gain) on early extinguishment of liabilities, net	21,141			—			22,479			(30,890		)
Revaluation of investments	—			—			—			14,365
Equity-based compensation expense (2)	12,228			6,865			27,114			39,859
Acquisition expense (3)	186			378			132			1,539
Revaluation of liabilities	—			—			5,600			—
Other (4)	448			617			3,089			7,734
Adjusted EBITDA	$	122,648		$	120,748		$	252,329		$	260,154


(1)	Amount reflects the difference between the market value of the inventory of our Refined Products and Renewables segment at the balance sheet date and its cost. See “Non-GAAP Financial Measures” section above for a further discussion.

(2)

Equity-based compensation expense in the table above may differ from equity-based compensation expense reported in Note 10 to our unaudited condensed consolidated financial statements included in this Quarterly Report. Amounts reported in the table above include expense accruals for bonuses expected to be paid in common units, whereas the amounts reported in Note 10 to our unaudited condensed consolidated financial statements only include expenses associated with equity-based awards that have been formally granted.


(3)	Amounts represent expenses we incurred related to legal and advisory costs associated with acquisitions, partially offset by reimbursement for certain legal costs incurred in prior periods.

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(4)

Amounts for the three months ended December 31, 2017 and 2016 and the nine months ended December 31, 2017 represent non-cash operating expenses related to our Grand Mesa Pipeline and accretion expense for asset retirement obligations. The amount for the nine months ended December 31, 2016 represents non-cash operating expenses related to our Grand Mesa Pipeline, adjustments related to noncontrolling interests and accretion expense for asset retirement obligations.

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



	Three Months Ended December 31,						Nine Months Ended December 31,
	2017			2016			2017			2016
	(in thousands)
Reconciliation to unaudited condensed consolidated statements of operations:
Depreciation and amortization per EBITDA table	$	67,025		$	64,644		$	204,514		$	171,746
Intangible asset amortization recorded to cost of sales	(1,505		)	(1,753		)	(4,596		)	(5,098		)
Depreciation and amortization of unconsolidated entities	(2,483		)	(3,048		)	(8,511		)	(9,116		)
Depreciation and amortization attributable to noncontrolling interests	303			924			1,020			2,744
Depreciation and amortization per unaudited condensed consolidated statements of operations	$	63,340		$	60,767		$	192,427		$	160,276



	Nine Months Ended December 31,
	2017			2016
	(in thousands)
Reconciliation to unaudited condensed consolidated statements of cash flows:
Depreciation and amortization per EBITDA table	$	204,514		$	171,746
Amortization of debt issuance costs recorded to interest expense	8,169			8,192
Depreciation and amortization of unconsolidated entities	(8,511		)	(9,116		)
Depreciation and amortization attributable to noncontrolling interests	1,020			2,744
Depreciation and amortization per unaudited condensed consolidated statements of cash flows	$	205,192		$	173,566

The following table reconciles interest expense per the EBITDA table above to interest expense reported in our unaudited condensed consolidated statements of operations for the periods indicated:



	Three Months Ended December 31,						Nine Months Ended December 31,
	2017			2016			2017			2016
	(in thousands)
Interest expense per EBITDA table	$	51,825		$	41,486		$	151,391		$	105,283
Interest expense attributable to noncontrolling interests	7			9			25			17
Interest expense attributable to unconsolidated entities	(42		)	(59		)	(167		)	16
Interest expense per unaudited condensed consolidated statements of operations	$	51,790		$	41,436		$	151,249		$	105,316

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The following tables reconcile operating income (loss) to Adjusted EBITDA by segment for the periods indicated. We have revised certain prior period information to be consistent with the calculation method used in the current fiscal year.



	Three Months Ended December 31, 2017
	Crude Oil Logistics			Water Solutions			Liquids			Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating income (loss)	$	106,279		$	(1,373	)	$	22,290		$	23,972		$	(4,791	)	$	(21,846	)	$	124,531
Depreciation and amortization	20,092			24,586			6,247			11,130			323			962			63,340
Amortization recorded to cost of sales	85			—			70			—			1,350			—			1,505
Net unrealized losses (gains) on derivatives	962			8,504			(8,550		)	(141		)	—			—			775
Inventory valuation adjustment	—			—			—			—			27,786			—			27,786
Lower of cost or market adjustments	5,207			—			—			—			(9,114		)	—			(3,907		)
(Gain) loss on disposal or impairment of assets, net	(107,574		)	2,929			(214		)	908			(7,529		)	—			(111,480		)
Equity-based compensation expense	—			—			—			—			—			12,228			12,228
Acquisition expense	—			—			—			—			—			186			186
Other income, net	5			190			93			29			151			1,639			2,107
Adjusted EBITDA attributable to unconsolidated entities	3,887			144			—			902			1,018			—			5,951
Adjusted EBITDA attributable to noncontrolling interest	—			(185		)	—			(637		)	—			—			(822		)
Other	1,377			91			21			(1,041		)	—			—			448
Adjusted EBITDA	$	30,320		$	34,886		$	19,957		$	35,122		$	9,194		$	(6,831	)	$	122,648



	Three Months Ended December 31, 2016
	Crude Oil Logistics			Water Solutions			Liquids			Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating (loss) income	$	(9,163	)	$	(11,898	)	$	24,765		$	21,772		$	8,209		$	(11,128	)	$	22,557
Depreciation and amortization	16,503			27,150			4,441			11,379			404			890			60,767
Amortization recorded to cost of sales	100			—			195			—			1,458			—			1,753
Net unrealized losses (gains) on derivatives	732			(1,304		)	(3,387		)	2			—			—			(3,957		)
Inventory valuation adjustment	—			—			—			—			7,859			—			7,859
Lower of cost or market adjustments	—			—			—			—			731			—			731
Loss (gain) on disposal or impairment of assets, net	4,655			2,323			60			(62		)	(6,941		)	(1		)	34
Equity-based compensation expense	—			—			—			—			—			6,865			6,865
Acquisition expense	—			—			—			(2		)	—			380			378
Other income, net	721			1,214			4			19			16,220			1,829			20,007
Adjusted EBITDA attributable to unconsolidated entities	2,577			54			—			(111		)	1,867			—			4,387
Adjusted EBITDA attributable to noncontrolling interest	—			(667		)	—			(583		)	—			—			(1,250		)
Other	481			116			20			—			—			—			617
Adjusted EBITDA	$	16,606		$	16,988		$	26,098		$	32,414		$	29,807		$	(1,165	)	$	120,748

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	Nine Months Ended December 31, 2017
	Crude Oil Logistics			Water Solutions			Liquids			Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating income (loss)	$	111,832		$	(10,075	)	$	(104,589	)	$	8,878		$	30,747		$	(56,031	)	$	(19,238	)
Depreciation and amortization	61,885			73,847			18,718			34,205			971			2,801			192,427
Amortization recorded to cost of sales	254			—			211			—			4,131			—			4,596
Net unrealized losses on derivatives	2,473			11,526			2,763			89			—			—			16,851
Inventory valuation adjustment	—			—			—			—			6,439			—			6,439
Lower of cost or market adjustments	5,207			—			—			—			297			—			5,504
(Gain) loss on disposal or impairment of assets, net	(111,290		)	3,114			117,515			2,004			(22,585		)	—			(11,242		)
Equity-based compensation expense	—			—			—			—			—			27,114			27,114
Acquisition expense	—			—			—			—			—			132			132
Other income, net	99			210			100			280			486			4,938			6,113
Adjusted EBITDA attributable to unconsolidated entities	11,507			425			—			891			3,125			—			15,948
Adjusted EBITDA attributable to noncontrolling interest	—			(619		)	—			(385		)	—			—			(1,004		)
Revaluation of liabilities	—			5,600			—			—			—			—			5,600
Other	3,790			276			64			(1,041		)	—			—			3,089
Adjusted EBITDA	$	85,757		$	84,304		$	34,782		$	44,921		$	23,611		$	(21,046	)	$	252,329



	Nine Months Ended December 31, 2016
	Crude Oil Logistics			Water Solutions			Liquids		Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating (loss) income	$	(28,827	)	$	63,136		$	33,092	$	10,553		$	169,365		$	(66,690	)	$	180,629
Depreciation and amortization	34,496			76,713			13,315		31,771			1,237			2,744			160,276
Amortization recorded to cost of sales	284			—			585		—			4,229			—			5,098
Net unrealized losses (gains) on derivatives	951			(2,138		)	239		211			—			—			(737		)
Inventory valuation adjustment	—			—			—		—			40,552			—			40,552
Lower of cost or market adjustments	—			—			—		—			839			—			839
Loss (gain) on disposal or impairment of assets, net	14,617			(91,958		)	109		(96		)	(126,101		)	(4		)	(203,433		)
Equity-based compensation expense	—			—			—		—			—			39,859			39,859
Acquisition expense	—			—			—		—			—			1,539			1,539
Other (expense) income, net	(589		)	1,524			67		339			19,099			5,420			25,860
Adjusted EBITDA attributable to unconsolidated entities	7,651			(9		)	—		(388		)	3,543			—			10,797
Adjusted EBITDA attributable to noncontrolling interest	—			(2,298		)	—		(442		)	—			—			(2,740		)
Other	1,276			279			60		—			—			—			1,615
Adjusted EBITDA	$	29,859		$	45,249		$	47,467	$	41,948		$	112,763		$	(17,132	)	$	260,154

Liquidity, Sources of Capital and Capital Resource Activities

Our principal sources of liquidity and capital are the cash flows from our operations, borrowings under our Revolving Credit Facility (as defined herein) and accessing capital markets. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a detailed description of our long-term debt. Our cash flows from operations are discussed below.

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Our borrowing needs vary during the year due in part to the seasonal nature of our Liquids, Retail Propane and Refined Products and Renewables businesses. 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 as well as building our gasoline inventories in anticipation of the winter gasoline contango and blending 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 and gasoline inventories need to be minimized due to certain inventory requirements.

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.

We believe that our anticipated cash flows from operations and the borrowing capacity under our Revolving Credit Facility (as defined herein) 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 or sell assets. 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.

Under current market conditions, we are much less likely to pursue acquisitions than we have been in the past. We continue to undertake certain capital expansion projects. We expect to be able to finance these projects through available capacity on our Revolving Credit Facility, asset sales or other forms of financing.

Other sources of liquidity during the nine months ended December 31, 2017 are discussed below.

Class B Preferred Units

Disposals

On December 22, 2017, we sold our previously held 50% interest in Glass Mountain for net proceeds of $292.1 million.

On November 7, 2017, we entered into a definitive agreement with DCC LPG, a division of DCC plc, to sell a portion of our Retail Propane segment for $200 million. We will retain this business through closing, which is expected to be March 31, 2018.

Long-Term Debt

Credit Agreement

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On June 2, 2017, we amended our Credit Agreement to, among other things, modify our financial covenants. In addition, the amendment also restricts us from increasing our distribution rate over the amount paid in the preceding quarter if our leverage ratio is greater than 4.25 to 1.

At December 31, 2017, we were in compliance with the covenants under the Credit Agreement.

Senior Secured Notes

During the nine months ended December 31, 2017, we repurchased all of our remaining outstanding senior secured notes for an aggregate purchase price of $250.2 million (excluding payments of accrued interest), and recorded a loss on the early extinguishment of $24.0 million (net of $4.3 million of debt issuance costs). Prior to the December 29, 2017 repurchase of all of the remaining outstanding senior secured notes, we made a semi-annual principal installment payment of $19.5 million on December 19, 2017.

Senior Unsecured Notes

The senior unsecured notes include the 2019 Notes, 2021 Notes, 2023 Notes and the 2025 Notes.

Repurchases

During the nine months ended December 31, 2017, we repurchased $18.7 million of the 2019 Notes, $43.4 million of the 2023 Notes, and $87.5 million of the 2025 Notes. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion of the repurchases.

Compliance

At December 31, 2017, we were in compliance with the covenants under the indentures for all of the senior unsecured notes.

For a further discussion of our Revolving Credit Facility, senior secured notes and senior unsecured notes, see Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report.

Revolving Credit Balances

The following table summarizes our Revolving Credit Facility borrowings for the periods indicated:



	Average Balance Outstanding		Lowest Balance		Highest Balance
	(in thousands)
Nine Months Ended December 31, 2017
Expansion capital borrowings	$	139,704	$	—	$	397,000
Working capital borrowings	$	811,536	$	719,500	$	1,014,500

Nine Months Ended December 31, 2016
Expansion capital borrowings	$	1,133,071	$	638,000	$	1,359,000
Working capital borrowings	$	662,660	$	465,500	$	875,500

At-The-Market Program

On August 24, 2016, we entered into an equity distribution agreement in connection with an at-the-market program (the “ATM Program”) pursuant to which we may issue and sell up to $200.0 million of common units. We are under no obligation to issue equity under the ATM Program. We did not issue any common units under the ATM Program during the nine months ended December 31, 2017, and approximately $134.7 million remained available for sale under the ATM Program at December 31, 2017.

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Common Unit Repurchase Program

Capital Expenditures, Acquisitions and Other Investments

The following table summarizes expansion and maintenance capital expenditures (which excludes additions for tank bottoms and line fill and has been prepared on the accrual basis), acquisitions and other investments for the periods indicated.



	Capital Expenditures						Other
	Expansion		Maintenance		Acquisitions		Investments (1)
	(in thousands)
Three Months Ended December 31,
2017	$	39,143	$	12,156	$	1,047	$	13,724
2016	$	60,330	$	5,205	$	14,216	$	52

Nine Months Ended December 31,
2017	$	83,175	$	26,677	$	49,481	$	27,874
2016	$	246,167	$	17,901	$	127,513	$	42,737


(1)	Amounts for the three months and nine months ended December 31, 2017 primarily related to contributions made to unconsolidated entities. Amounts for the three months and nine months ended December 31, 2016 primarily related to payments made to terminate a development agreement and other liabilities.

Cash Flows

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



	Nine Months Ended December 31,
Cash Flows Provided by (Used in)	2017			2016
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	168,825		$	194,858
Changes in operating assets and liabilities	(164,764		)	(310,430		)
Operating activities	$	4,061		$	(115,572	)
Investing activities	$	105,052		$	(331,070	)
Financing activities	$	(92,908	)	$	447,393

Operating Activities. The seasonality of our natural gas liquids businesses has a significant effect 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 our Liquids and Retail Propane businesses, we typically experience operating losses or lower operating income during our first and second quarters, or the six months ending September 30, as a result of lower volumes of natural gas liquids sales and when we are building our inventory levels for the upcoming heating season. The heating season runs through the six months ending March 31. The seasonal motor fuel blending impacts the value of our gasoline inventory in our Refined Products and Renewables business and also represents a period when we build inventory into our system. We borrow under our Revolving Credit Facility to supplement our operating cash flows during the periods in which we are building inventory. Our operations, and as a result our cash flows, are also impacted by positive and negative movements in commodity prices, which cause fluctuations in the value of inventory, accounts receivable and payables, due to increases and decreases in revenues and cost of sales. The increase in net cash provided by operating activities during the nine months ended December 31, 2017 was due primarily to higher inventory as a result of the

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purchase of additional pipeline capacity allocations in our Refined Products and Renewables segment during the nine months ended December 31, 2016.

Investing Activities. Net cash provided by investing activities was $105.1 million during the nine months ended December 31, 2017, compared to net cash used in investing activities of $331.1 million during the nine months ended December 31, 2016. The increase in net cash provided by investing activities was due primarily to:


•	a $177.2 million increase in proceeds from sales of assets due primarily to the sale of our previously held 50% interest in Glass Mountain and an increase in proceeds from the sale of excess pipe in our Crude Oil Logistics segment during the nine months ended December 31, 2017 and the sale of TLP common units we owned and Grassland during the nine months ended December 31, 2016;


•	a decrease in capital expenditures from $264.6 million during the nine months ended December 31, 2016, primarily related to the Grand Mesa Pipeline, to $99.4 million during the nine months ended December 31, 2017;


•	a $50.1 million decrease in cash paid for acquisitions and investments in and transactions with unconsolidated entities during the nine months ended December 31, 2017;


•	a $20.0 million deposit received related to the potential sale of a portion of our Retail Propane segment during the nine months ended December 31, 2017; and


•	a $16.9 million payment to terminate a development agreement during the nine months ended December 31, 2016.

Financing Activities. Net cash used in financing activities was $92.9 million during the nine months ended December 31, 2017, compared to net cash provided by financing activities of $447.4 million during the nine months ended December 31, 2016. The increase in net cash used in financing activities was due primarily to:


•	$700.0 million in proceeds received from the issuance of the 2023 Notes during the nine months ended December 31, 2016;


•	an increase of $400.4 million for repayments and repurchases of all of our remaining outstanding senior secured notes and a portion of our senior unsecured notes during the nine months ended December 31, 2017;


•	a decrease of $76.2 million in proceeds received from the sale of our common units and preferred units during the nine months ended December 31, 2017;


•	an increase of $34.2 million in distributions paid to our general partners and common unit holders, preferred unitholders and noncontrolling interest owners during the nine months ended December 31, 2017; and


•	$26.2 million for the repurchase of a portion of our common units and warrants related to our Class A Preferred Units during the nine months ended December 31, 2017.

These increases in net cash used in financing activities were partially offset by:


•	an increase of $659.5 million in borrowings on our Revolving Credit Facility (net of repayments) during the nine months ended December 31, 2017; and


•	a $25.9 million release of contingent consideration liabilities related to the termination of a development agreement during the nine months ended December 31, 2016.

Distributions Declared

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. See further discussion of our cash distribution policy in Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities included in our Annual Report.

On December 19, 2017, the board of directors of our general partner declared a distribution on the Class B Preferred Units for the three months ended December 31, 2017 of $4.7 million, which was paid to the holders of the Class B Preferred Units on January 15, 2018.

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On January 23, 2018, the board of directors of our general partner declared a distribution of $0.39 per common unit to the unitholders of record on February 6, 2018. In addition, the board of directors declared a distribution to the holders of the Class A Preferred Units of $6.4 million in the aggregate. The distributions to both the common unitholders and the holders of the Class A Preferred Units are to be paid on February 14, 2018.

For a further discussion of our distributions, see Note 10 to our unaudited condensed consolidated financial statements included in this Quarterly Report.

Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2017 for our fiscal years ending thereafter:



			Three Months Ending March 31,		Fiscal Year Ending March 31,
	Total		2018		2019		2020		2021		2022		Thereafter
	(in thousands)
Principal payments on long-term debt:
Expansion capital borrowings	$	125,000	$	—	$	—	$	—	$	—	$	125,000	$	—
Working capital borrowings	1,014,500		—		—		—		—		1,014,500		—
Senior unsecured notes	1,796,925		—		—		360,781				367,048		1,069,096
Other long-term debt	11,684		604		2,939		2,318		5,470		286		67
Interest payments on long-term debt:
Revolving Credit Facility (1)	238,503		15,289		62,004		62,004		62,004		37,202		—
Senior unsecured notes	622,879		21,878		118,235		108,990		99,745		99,745		174,286
Other long-term debt	1,187		174		498		341		157		14		3
Letters of credit	182,123		—		—		—		—		182,123		—
Future minimum lease payments under noncancelable operating leases	516,712		34,721		120,928		107,342		93,662		66,036		94,023
Future minimum throughput payments under noncancelable agreements (2)	107,394		13,001		52,042		42,351		—		—		—
Construction commitments (3)	6,211		3,650		2,561		—		—		—		—
Fixed-price commodity purchase commitments:
Crude oil	51,001		51,001		—		—		—		—		—
Natural gas liquids	21,941		20,600		1,341		—		—		—		—
Index-price commodity purchase commitments (4):
Crude oil (5)	2,972,749		427,214		790,287		511,636		438,851		357,603		447,158
Natural gas liquids	356,683		310,124		46,559		—		—		—		—
Total contractual obligations	$	8,025,492	$	898,256	$	1,197,394	$	1,195,763	$	699,889	$	2,249,557	$	1,337,475


(1)	The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at December 31, 2017. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for additional information on our Credit Agreement.

(2)

We have executed noncancelable agreements with crude oil operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity. Under certain agreements we have the ability to recover minimum shipping fees previously paid if our shipping volumes exceed the minimum monthly shipping commitment during each month remaining under the agreement. See Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report for additional information.


(3)	At December 31, 2017, construction commitments primarily relate to the expansion of the Lucerne, Colorado crude oil tank storage.

(4)

Index prices are based on a forward price curve at December 31, 2017. A theoretical change of $0.10 per gallon of natural gas liquids in the underlying commodity price at December 31, 2017 would result in a change of $37.0 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel of crude oil in the underlying commodity price at December 31, 2017 would result in a change of $59.1 million in the value of our index-price crude oil purchase commitments. See Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report for further detail of the commitments.

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(5)

Our crude oil index-price purchase commitments exceed our crude oil index-price sales commitments (see Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report) due primarily to our long-term purchase commitments for crude oil that we purchase and ship on the Grand Mesa pipeline. As these purchase commitments are deliver-or-pay contracts, we have not entered into corresponding long-term sales contracts for volumes we may not receive.

Off-Balance Sheet Arrangements

We do not have any off balance sheet arrangements other than the operating leases discussed in Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report.

Environmental Legislation

See our Annual Report 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.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements that are applicable to us, see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report.

Critical Accounting Policies

The preparation of financial statements and related disclosures in conformity with GAAP requires the selection and application of appropriate accounting principles to the relevant facts and circumstances of our operations and the use of estimates made by management. We have identified certain accounting policies that are most important to the portrayal of our consolidated financial position and results of operations. The application of these accounting policies, which requires subjective or complex 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. There have been no material changes in the critical accounting policies previously disclosed in our Annual Report.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

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 our fixed-rate debt but do not impact its cash flows.

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At December 31, 2017, we had $1.1 billion of outstanding borrowings under our Revolving Credit Facility at a weighted average interest rate of 4.90%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.4 million, based on borrowings outstanding at December 31, 2017.

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, or refined and renewables 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. Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions. At December 31, 2017, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.

The crude oil, natural gas liquids, and refined and renewables products industries are “margin-based” and “cost-plus” businesses in which gross profits depend on the differential of sales prices over supply costs. We have no control over market conditions. As a result, our profitability may be impacted by sudden and significant changes in the price of crude oil, natural gas liquids, and refined and renewables products.

We engage in various types of forward contracts and financial derivative transactions to reduce the effect of price volatility on our product costs, to 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 financial derivative instruments to reduce the market price risk associated with forecasted transactions, we do not account for financial derivative transactions as hedges. We record the changes in fair value of these financial derivative transactions within cost of sales in our unaudited condensed consolidated statements of operations. The following table summarizes the hypothetical impact on the December 31, 2017 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)	$	(8,840	)
Propane (Liquids segment)	$	744
Other products (Liquids segment)	$	(2,625	)
Gasoline (Refined Products and Renewables segment)	$	(23,456	)
Diesel (Refined Products and Renewables segment)	$	(18,277	)
Ethanol (Refined Products and Renewables segment)	$	(3,728	)
Biodiesel (Refined Products and Renewables segment)	$	3,785
Canadian dollars (Liquids segment)	$	705

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Fair Value

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


Item 4.	Controls and Procedures

We maintain disclosure controls and procedures, as defined in Rule 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 the 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 the 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, 2017. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of December 31, 2017, such disclosure controls and procedures were effective to provide the reasonable assurance described above.

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, 2017 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

We are involved from time to time in various legal proceedings and claims arising in the ordinary course of business. For information related to legal proceedings, see the discussion under the captions “Legal Contingencies” and “Environmental Matters” in Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report, which information is incorporated by reference into this Item 1.

Item 1A. Risk Factors

There have been no material changes in the risk factors previously disclosed in Part I, Item 1A–“Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended March 31, 2017, 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, 2017.

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

Common Unit Repurchase Program

On August 29, 2017, the board of directors of our general partner authorized a common unit repurchase program, under which we may repurchase up to $15.0 million of our outstanding common units through December 31, 2017 from time to time in the open market or in other privately negotiated transactions. The common unit repurchase program authorization does not obligate us to repurchase any dollar amount or number of our common units. The following table summarizes the repurchase of common units during the three months ended December 31, 2017:



				Total Number of
				Common Units	Approximate Dollar Value
	Total Number of	Average Price		Purchased as Part	of Common Units
	Common Units	Paid Per		of Publicly Announced	that May Yet Be Purchased
Period	Purchased	Common Unit		Program	Under the Program
October 1-31, 2017	—	$	—	—	$	3,847,062
November 1-30, 2017	327,309	$	12.02	323,213	$	—
December 1-31, 2017	—	$	—	—	$	—
Total	327,309			323,213	$	—

The common units not repurchased under the publicly announced program were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units. As a result, we are including the common units surrendered in the Total Number of Common Units Purchased column.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Amendment to Credit Agreement

On February 5, 2018, NGL Energy Partners LP (the “Partnership”), NGL Energy Operating LLC, in its capacity as borrowers’ agent and the other subsidiary borrowers party thereto entered into Amendment No. 3 (the “Credit Agreement Amendment”) to the Partnership’s Amended and Restated Credit Agreement (the “Credit Agreement”) with Deutsche Bank Trust Company Americas, as administrative agent, and the other financial institutions party thereto. Among other changes, the Credit Agreement Amendment amended the defined term “Consolidated EBITDA.”

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“Consolidated EBITDA,” solely for the two quarters ending December 31, 2017 and March 31, 2018, may be adjusted to include the Accrued Blenders Tax Credits (as defined in the Credit Agreement).

The Credit Agreement Amendment is filed as Exhibit 10.1 to this Quarterly Report on Form 10-Q and is incorporated herein by reference. The above description of the material terms of the Credit Agreement Amendment does not purport to be complete and is qualified in its entirety by reference to Exhibit 10.1.

Item 6. Exhibits



Exhibit Number		Exhibit
10.1*		Amendment No. 3 to Amended and Restated Credit Agreement, dated as of February 5, 2018, among NGL Energy Partners LP, NGL Energy Operating LLC, the other subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas, and the other financial institutions party thereto
12.1*		Computation of ratios of earnings to fixed charges and combined fixed charges and preferred unit distributions
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) Unaudited Condensed Consolidated Balance Sheets at December 31, 2017 and March 31, 2017, (ii) Unaudited Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2017 and 2016, (iii) Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and nine months ended December 31, 2017 and 2016, (iv) Unaudited Condensed Consolidated Statement of Changes in Equity for the nine months ended December 31, 2017, (v) Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2017 and 2016, and (vi) Notes to Unaudited 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, 2018		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer

Date: February 9, 2018		By:	/s/ Robert W. Karlovich III
			Robert W. Karlovich III
			Chief Financial Officer