NGL Energy Partners LP - Quarter Report: 2017 September (Form 10-Q)

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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 September 30, 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 November 3, 2017, there were 120,512,692 common units issued and outstanding.

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PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements	3
	Unaudited Condensed Consolidated Balance Sheets at September 30, 2017 and March 31, 2017	3
	Unaudited Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2017 and 2016	4
	Unaudited Condensed Consolidated Statements of Comprehensive (Loss) Income for the three months and six months ended September 30, 2017 and 2016	5
	Unaudited Condensed Consolidated Statement of Changes in Equity for the six months ended September 30, 2017	6
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 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	46
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	80
Item 4.	Controls and Procedures	81
PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	82
Item 1A.	Risk Factors	82
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	82
Item 3.	Defaults Upon Senior Securities	82
Item 4.	Mine Safety Disclosures	82
Item 5.	Other Information	82
Item 6.	Exhibits	83
SIGNATURES		84

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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)



	September 30, 2017			March 31, 2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	18,407		$	12,264
Accounts receivable-trade, net of allowance for doubtful accounts of $5,799 and $5,234, respectively	841,645			800,607
Accounts receivable-affiliates	2,918			6,711
Inventories	570,733			561,432
Prepaid expenses and other current assets	112,517			103,193
Total current assets	1,546,220			1,484,207
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $432,820 and $375,594, respectively	1,768,485			1,790,273
GOODWILL	1,339,416			1,451,716
INTANGIBLE ASSETS, net of accumulated amortization of $435,457 and $414,605, respectively	1,112,535			1,163,956
INVESTMENTS IN UNCONSOLIDATED ENTITIES	198,281			187,423
LOAN RECEIVABLE-AFFILIATE	4,160			3,200
OTHER NONCURRENT ASSETS	240,561			239,604
Total assets	$	6,209,658		$	6,320,379
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	635,312		$	658,021
Accounts payable-affiliates	4,749			7,918
Accrued expenses and other payables	227,069			207,125
Advance payments received from customers	80,378			35,944
Current maturities of long-term debt	42,373			29,590
Total current liabilities	989,881			938,598
LONG-TERM DEBT, net of debt issuance costs of $29,094 and $33,458, respectively, and current maturities	2,993,461			2,963,483
OTHER NONCURRENT LIABILITIES	175,885			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	71,009			63,890
REDEEMABLE NONCONTROLLING INTEREST	3,129			3,072

EQUITY:
General partner, representing a 0.1% interest, 120,633 and 120,300 notional units, respectively	(50,872		)	(50,529		)
Limited partners, representing a 99.9% interest, 120,512,692 and 120,179,407 common units issued and outstanding, respectively	1,819,491			2,192,413
Class B preferred limited partners, 8,400,000 and 0 preferred units issued and outstanding, respectively	202,755			—
Accumulated other comprehensive loss	(2,262		)	(1,828		)
Noncontrolling interests	7,181			26,746
Total equity	1,976,293			2,166,802
Total liabilities and equity	$	6,209,658		$	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 September 30,						Six Months Ended September 30,
	2017			2016			2017			2016
REVENUES:
Crude Oil Logistics	$	437,022		$	349,885		$	941,937		$	775,836
Water Solutions	51,032			39,733			97,999			75,486
Liquids	393,123			234,260			670,937			439,309
Retail Propane	64,700			51,090			131,772			111,477
Refined Products and Renewables	2,977,206			2,370,322			5,861,843			4,364,885
Other	246			248			407			515
Total Revenues	3,923,329			3,045,538			7,704,895			5,767,508
COST OF SALES:
Crude Oil Logistics	401,170			340,518			870,640			745,748
Water Solutions	2,674			(1,807		)	2,827			3,394
Liquids	377,569			209,283			648,643			400,275
Retail Propane	31,320			20,691			60,956			45,511
Refined Products and Renewables	2,957,867			2,359,932			5,829,569			4,300,019
Other	121			113			194			223
Total Cost of Sales	3,770,721			2,928,730			7,412,829			5,495,170
OPERATING COSTS AND EXPENSES:
Operating	75,970			73,255			152,439			148,427
General and administrative	23,480			27,926			48,471			69,797
Depreciation and amortization	65,208			50,603			129,087			99,509
Loss (gain) on disposal or impairment of assets, net	111,452			852			100,238			(203,467		)
Revaluation of liabilities	5,600			—			5,600			—
Operating (Loss) Income	(129,102		)	(35,828		)	(143,769		)	158,072
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	2,028			53			3,844			447
Revaluation of investments	—			—			—			(14,365		)
Interest expense	(50,233		)	(33,442		)	(99,459		)	(63,880		)
Gain (loss) on early extinguishment of liabilities, net	1,943			938			(1,338		)	30,890
Other income, net	1,896			2,081			4,006			5,853
(Loss) Income Before Income Taxes	(173,468		)	(66,198		)	(236,716		)	117,017
INCOME TAX EXPENSE	(111		)	(460		)	(570		)	(922		)
Net (Loss) Income	(173,579		)	(66,658		)	(237,286		)	116,095
LESS: NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(80		)	59			(132		)	(5,774		)
LESS: NET LOSS ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS	288			—			685			—
NET (LOSS) INCOME ATTRIBUTABLE TO NGL ENERGY PARTNERS LP	(173,371		)	(66,599		)	(236,733		)	110,321
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS	(16,098		)	(8,668		)	(25,782		)	(12,052		)
LESS: NET LOSS (INCOME) ALLOCATED TO GENERAL PARTNER	154			45			194			(158		)
LESS: REPURCHASE OF WARRANTS	—			—			(349		)	—
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$	(189,315	)	$	(75,222	)	$	(262,670	)	$	98,111
BASIC (LOSS) INCOME PER COMMON UNIT	$	(1.56	)	$	(0.71	)	$	(2.17	)	$	0.93
DILUTED (LOSS) INCOME PER COMMON UNIT	$	(1.56	)	$	(0.71	)	$	(2.17	)	$	0.91
BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	121,314,636			106,186,389			120,927,400			105,183,556
DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	121,314,636			106,186,389			120,927,400			107,997,549

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 (Loss) Income

(in Thousands)



	Three Months Ended September 30,						Six Months Ended September 30,
	2017			2016			2017			2016
Net (loss) income	$	(173,579	)	$	(66,658	)	$	(237,286	)	$	116,095
Other comprehensive loss	(59		)	(333		)	(434		)	(485		)
Comprehensive (loss) income	$	(173,638	)	$	(66,991	)	$	(237,720	)	$	115,610

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

Six Months Ended September 30, 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)	(161		)	—	—		—		(112,898		)	—			—			(113,059		)
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)	—			—	—		—		(741		)	—			—			(741		)
Repurchase of warrants (Note 10)	—			—	—		—		(10,549		)	—			—			(10,549		)
Equity issued pursuant to incentive compensation plan (Note 10)	12			—	—		956,821		12,920			—			—			12,932
Common unit repurchases (Note 10)	—			—	—		(1,231,189	)	(11,663		)	—			—			(11,663		)
Conversion of warrants (Note 10)	—			—	—		607,653		6			—			—			6
Accretion of beneficial conversion feature of Class A convertible preferred units (Note 10)	—			—	—		—		(7,213		)	—			—			(7,213		)
Issuance of Class B preferred units (Note 10)	—			8,400,000	202,755		—		—			—			—			202,755
Net (loss) income	(194		)	—	—		—		(236,539		)	—			132			(236,601		)
Other comprehensive loss	—			—	—		—		—			(434		)	—			(434		)
BALANCES AT SEPTEMBER 30, 2017	$	(50,872	)	8,400,000	$	202,755	120,512,692		$	1,819,491		$	(2,262	)	$	7,181		$	1,976,293

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)



	Six Months Ended September 30,
	2017			2016
OPERATING ACTIVITIES:
Net (loss) income	$	(237,286	)	$	116,095
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depreciation and amortization, including amortization of debt issuance costs	137,687			108,133
Loss (gain) on early extinguishment or revaluation of liabilities, net	6,938			(30,890		)
Non-cash equity-based compensation expense	14,886			32,994
Loss (gain) on disposal or impairment of assets, net	100,238			(203,467		)
Provision for doubtful accounts	170			(122		)
Net adjustments to fair value of commodity derivatives	34,882			44,966
Equity in earnings of unconsolidated entities	(3,844		)	(447		)
Distributions of earnings from unconsolidated entities	2,777			42
Revaluation of investments	—			14,365
Other	9,399			(2,938		)
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable-trade and affiliates	(37,903		)	(54,069		)
Inventories	(18,585		)	(151,507		)
Other current and noncurrent assets	(24,762		)	(44,798		)
Accounts payable-trade and affiliates	(27,412		)	90,496
Other current and noncurrent liabilities	52,769			26,270
Net cash provided by (used in) operating activities	9,954			(54,877		)
INVESTING ACTIVITIES:
Capital expenditures	(56,468		)	(201,633		)
Acquisitions, net of cash acquired	(48,434		)	(113,297		)
Cash flows from settlements of commodity derivatives	(22,039		)	(25,015		)
Proceeds from sales of assets	24,586			396
Proceeds from sale of TLP common units	—			112,370
Investments in unconsolidated entities	(14,150		)	—
Distributions of capital from unconsolidated entities	4,378			5,233
Payments on loan for natural gas liquids facility	4,875			4,324
Loan to affiliate	(960		)	(1,700		)
Payments on loan to affiliate	—			655
Payment to terminate development agreement	—			(16,875		)
Net cash used in investing activities	(108,212		)	(235,542		)
FINANCING ACTIVITIES:
Proceeds from borrowings under Revolving Credit Facility	814,500			770,000
Payments on Revolving Credit Facility	(657,500		)	(595,500		)
Repurchase of senior secured and senior unsecured notes	(115,407		)	(15,129		)
Payments on other long-term debt	(3,163		)	(4,423		)
Debt issuance costs	(2,474		)	(320		)
Contributions from general partner	—			59
Contributions from noncontrolling interest owners, net	23			465
Distributions to general and common unit partners and preferred unitholders	(107,389		)	(83,707		)
Distributions to noncontrolling interest owners	(3,082		)	(2,750		)
Proceeds from sale of preferred units, net of offering costs	202,755			235,018
Repurchase of warrants	(10,549		)	—
Common unit repurchases	(11,663		)	—
Proceeds from sale of common units, net of offering costs	—			9,383
Payments for settlement and early extinguishment of liabilities	(1,650		)	(27,406		)
Other	—			(20		)
Net cash provided by financing activities	104,401			285,670
Net increase (decrease) in cash and cash equivalents	6,143			(4,749		)
Cash and cash equivalents, beginning of period	12,264			28,176
Cash and cash equivalents, end of period	$	18,407		$	23,427
Supplemental cash flow information:
Cash interest paid	$	96,217		$	58,869
Income taxes paid (net of income tax refunds)	$	1,473		$	1,755
Supplemental non-cash investing and financing activities:
Distributions declared but not paid to Class B preferred unitholders	$	5,670		$	—
Accrued capital expenditures	$	2,907		$	2,073
Value of common units issued in business combinations	$	—		$	3,969

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 September 30, 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

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

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 September 30, 2017 and 2016 include $0.3 million and $1.2 million, respectively, and revenues during the six months ended September 30, 2017 and 2016 include $0.7 million and $2.5 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 the United States and in Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales.

We 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

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

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 September 30, 2017 or March 31, 2017.

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:



	September 30, 2017		March 31, 2017
	(in thousands)
Crude oil	$	81,969	$	146,857
Natural gas liquids:
Propane	107,364		38,631
Butane	93,257		5,992
Other	9,389		6,035
Refined products:
Gasoline	131,640		193,051
Diesel	90,696		98,237
Renewables:
Ethanol	31,273		42,009
Biodiesel	16,517		21,410
Other	8,628		9,210
Total	$	570,733	$	561,432

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 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.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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



Entity	Segment	Ownership Interest (1)	Date Acquired or Formed	September 30, 2017		March 31, 2017
				(in thousands)
Glass Mountain Pipeline, LLC (2)	Crude Oil Logistics	50%	December 2013	$	181,982	$	172,098
E Energy Adams, LLC	Refined Products and Renewables	19%	December 2013	14,264		12,952
Water treatment and disposal facility (3)	Water Solutions	50%	August 2015	2,035		2,147
Victory Propane, LLC (4)	Retail Propane	50%	April 2015	—		226
Total				$	198,281	$	187,423


(1)	Ownership interest percentages are at September 30, 2017.

(2)

Our investment in Glass Mountain Pipeline, LLC (“Glass Mountain”) exceeds our proportionate share of the historical net book value of Glass Mountain’s net assets by $71.5 million at September 30, 2017. This difference relates primarily to goodwill and customer relationships. We amortize the value of the customer relationships and record the expense within equity in earnings of unconsolidated entities in our unaudited condensed consolidated statement of operations.


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


(4)	This investment is negative at September 30, 2017 and has been reclassified to current liabilities within our unaudited condensed consolidated balance sheet as we believe the decline to be temporary.

Other Noncurrent Assets

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



	September 30, 2017		March 31, 2017
	(in thousands)
Loan receivable (1)	$	35,242	$	40,684
Line fill (2)	30,628		30,628
Tank bottoms (3)	42,044		42,044
Minimum shipping fees - pipeline commitments (4)	76,619		67,996
Other	56,028		58,252
Total	$	240,561	$	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 crude oil we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At September 30, 2017 and March 31, 2017, line fill consisted of 427,193 barrels and 427,193 barrels of crude oil, respectively. 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 September 30, 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 2.6 years and 3.0 years, respectively, in which to ship the excess volumes.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Accrued Expenses and Other Payables

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



	September 30, 2017		March 31, 2017
	(in thousands)
Accrued compensation and benefits	$	23,083	$	22,227
Excise and other tax liabilities	56,562		64,051
Derivative liabilities	28,942		27,622
Accrued interest	41,916		44,418
Product exchange liabilities	25,869		1,693
Deferred gain on sale of general partner interest in TLP	30,113		30,113
Other	20,584		17,001
Total	$	227,069	$	207,125

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 September 30, 2017 and 2016, we recognized $7.5 million and $7.5 million, respectively, and during the six months ended September 30, 2017 and 2016, we recognized $15.1 million and $15.1 million, respectively, of the deferred gain in our unaudited condensed consolidated statements of operations. Within our September 30, 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, $124.2 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 six months ended September 30, 2017, we recorded $0.7 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 six months ended September 30, 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. Also, certain line items in our unaudited condensed consolidated statement of cash flows were combined and the prior period amounts were combined to be consistent with the classification methods used in the current fiscal year.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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 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, 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 and have not yet determined whether they would be material to our consolidated financial statements. 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.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Note 3—(Loss) Income Per Common Unit

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



	Three Months Ended September 30,		Six Months Ended September 30,
	2017	2016	2017	2016
Weighted average units outstanding during the period:
Common units - Basic	121,314,636	106,186,389	120,927,400	105,183,556
Effect of Dilutive Securities:
Performance units	—	—	—	10,557
Warrants	—	—	—	2,803,436
Common units - Diluted	121,314,636	106,186,389	120,927,400	107,997,549

For the three months ended September 30, 2017 and 2016, and the six months ended September 30, 2017, Class A Preferred Units (as defined herein), warrants, Performance Awards (as defined herein), and Service Awards (as defined herein) were considered antidilutive. For the six months ended September 30, 2016, Class A Preferred Units and Service Awards were considered antidilutive.

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



	Three Months Ended September 30,						Six Months Ended September 30,
	2017			2016			2017			2016
	(in thousands, except unit and per unit amounts)
Net (loss) income	$	(173,579	)	$	(66,658	)	$	(237,286	)	$	116,095
Less: Net (income) loss attributable to noncontrolling interests	(80		)	59			(132		)	(5,774		)
Less: Net loss attributable to redeemable noncontrolling interests	288			—			685			—
Net (loss) income attributable to NGL Energy Partners LP	(173,371		)	(66,599		)	(236,733		)	110,321
Less: Distributions to preferred unitholders	(16,098		)	(8,668		)	(25,782		)	(12,052		)
Less: Net loss (income) allocated to general partner (1)	154			45			194			(158		)
Less: Repurchase of warrants (2)	—			—			(349		)	—
Net (loss) income allocated to common unitholders	$	(189,315	)	$	(75,222	)	$	(262,670	)	$	98,111
Basic (loss) income per common unit	$	(1.56	)	$	(0.71	)	$	(2.17	)	$	0.93
Diluted (loss) income per common unit	$	(1.56	)	$	(0.71	)	$	(2.17	)	$	0.91
Basic weighted average common units outstanding	121,314,636			106,186,389			120,927,400			105,183,556
Diluted weighted average common units outstanding	121,314,636			106,186,389			120,927,400			107,997,549


(1)	Net loss (income) 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 six months ended September 30, 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:

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


•	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 loss (gain) on disposal or impairment of assets, net in our unaudited condensed consolidated statement of operations during the six months ended September 30, 2017.

Retail Propane Businesses

During the six months ended September 30, 2017, we acquired four retail propane businesses for total consideration of $29.3 million. The agreements for these acquisitions contemplate post-closing payments for certain working capital items.

We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed for these retail propane businesses, and as a result, the estimates of fair value at September 30, 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	$	1,880
Property, plant and equipment	10,051
Goodwill	4,150
Intangible assets	14,875
Current liabilities	(1,484		)
Other noncurrent liabilities	(134		)
Fair value of net assets acquired	$	29,338

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 six months ended September 30, 2017 includes revenues of $2.8 million and operating income of less than $0.1 million that were generated by the operations of two 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.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Retail Propane Businesses

During the six months ended September 30, 2017, we completed the acquisition accounting for three retail propane businesses. During the six months ended September 30, 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 six months ended September 30, 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.

Note 5—Property, Plant and Equipment

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



Description	Estimated Useful Lives	September 30, 2017			March 31, 2017
		(in thousands)
Natural gas liquids terminal and storage assets	2–30 years	$	237,468		$	207,825
Pipeline and related facilities	30–40 years	255,894			248,582
Refined products terminal assets and equipment	15–25 years	6,736			6,736
Retail propane equipment	2–30 years	248,971			239,417
Vehicles and railcars	3–25 years	199,661			198,480
Water treatment facilities and equipment	3–30 years	576,765			557,100
Crude oil tanks and related equipment	2–30 years	217,610			203,003
Barges and towboats	5–30 years	91,884			91,037
Information technology equipment	3–7 years	44,531			43,880
Buildings and leasehold improvements	3–40 years	176,877			161,957
Land		61,221			56,545
Tank bottoms and line fill (1)		25,458			24,462
Other	3–20 years	20,840			39,132
Construction in progress		37,389			87,711
		2,201,305			2,165,867
Accumulated depreciation		(432,820		)	(375,594		)
Net property, plant and equipment		$	1,768,485		$	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.

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



	Three Months Ended September 30,				Six Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Depreciation expense	$	33,788	$	28,703	$	66,132	$	56,357
Capitalized interest expense	$	—	$	1,069	$	—	$	4,804

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

We record losses (gains) from the sales of property, plant and equipment and any write-downs in value due to impairment within loss (gain) on disposal or impairment of assets, net in our unaudited condensed consolidated statements of operations. During the three months ended September 30, 2017, we recorded a net loss of $1.9 million, of which $0.4 million related to a gain on the sale of excess pipe in our Crude Oil Logistics segment. During the six months ended September 30, 2017, we recorded a net gain of $0.6 million, of which $3.8 million related to the gain on the sale of excess pipe in our Crude Oil Logistics segment. The gain was partially offset by losses from the sale of certain assets and the write down of certain other assets.

Note 6—Goodwill

The following table summarizes changes in goodwill by segment during the six months ended September 30, 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)	—		—		—			4,150		—		4,150
Impairment	—		—		(116,877		)	—		—		(116,877		)
Balances at September 30, 2017	$	579,846	$	424,465	$	149,169		$	134,809	$	51,127	$	1,339,416

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 loss (gain) 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:



		September 30, 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	$	906,229	$	343,377	$	562,852	$	906,782	$	316,242	$	590,540
Customer commitments	10 years	310,000		28,417		281,583		310,000		12,917		297,083
Pipeline capacity rights	30 years	161,785		14,349		147,436		161,785		11,652		150,133
Rights-of-way and easements	1–40 years	63,669		2,901		60,768		63,402		2,154		61,248
Executory contracts and other agreements	3–30 years	23,097		16,433		6,664		29,036		20,457		8,579
Non-compete agreements	2–32 years	18,198		5,979		12,219		32,984		17,762		15,222
Trade names	1–10 years	4,074		1,736		2,338		15,439		13,396		2,043
Debt issuance costs (1)	5 years	40,790		22,265		18,525		38,983		20,025		18,958
Total amortizable		1,527,842		435,457		1,092,385		1,558,411		414,605		1,143,806
Non-amortizable:
Trade names		20,150		—		20,150		20,150		—		20,150
Total non-amortizable		20,150		—		20,150		20,150		—		20,150
Total		$	1,547,992	$	435,457	$	1,112,535	$	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.

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

Write off of Intangible Asset

During the six months ended September 30, 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 September 30,				Six Months Ended September 30,
Recorded In	2017		2016		2017		2016
	(in thousands)
Depreciation and amortization	$	31,420	$	21,900	$	62,955	$	43,152
Cost of sales	1,506		1,749		3,091		3,345
Interest expense	1,154		1,731		2,240		3,456
Total	$	34,080	$	25,380	$	68,286	$	49,953

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 (six months)	$	66,729
2019	129,561
2020	126,174
2021	113,067
2022	97,964
Thereafter	558,890
Total	$	1,092,385

Note 8—Long-Term Debt

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



	September 30, 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	$	102,000	$	—		$	102,000	$	—	$	—		$	—
Working capital borrowings	869,500		—			869,500		814,500		—			814,500
Senior secured notes	195,000		(3,514		)	191,486		250,000		(4,559		)	245,441
Senior unsecured notes:
5.125% Notes due 2019	360,781		(2,342		)	358,439		379,458		(3,191		)	376,267
6.875% Notes due 2021	367,048		(5,131		)	361,917		367,048		(5,812		)	361,236
7.500% Notes due 2023	673,543		(10,166		)	663,377		700,000		(11,329		)	688,671
6.125% Notes due 2025	484,300		(7,941		)	476,359		500,000		(8,567		)	491,433
Other long-term debt	12,756		—			12,756		15,525		—			15,525
	3,064,928		(29,094		)	3,035,834		3,026,531		(33,458		)	2,993,073
Less: Current maturities	42,373		—			42,373		29,590		—			29,590
Long-term debt	$	3,022,555	$	(29,094	)	$	2,993,461	$	2,996,941	$	(33,458	)	$	2,963,483


(1)	Debt issuance costs related to the Revolving Credit Facility (as defined herein) 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 $1.6 million and $1.0 million during the three months ended September 30, 2017 and 2016, respectively, and $3.3 million and $1.8 million during the six months ended September 30, 2017 and 2016, respectively.

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



Fiscal Year Ending March 31,
2018 (six months)	$	3,034
2019	6,061
2020	5,135
2021	4,754
2022	4,173
Thereafter	5,937
Total	$	29,094

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 September 30, 2017, the Credit Agreement includes a revolving credit facility to fund working capital needs, which had a capacity of $1.05 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 $715.0 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. We had letters of credit of $115.1 million on the Working Capital Facility at September 30, 2017.

At September 30, 2017, the borrowings under the Credit Agreement had a weighted average interest rate of 4.50%, calculated as the weighted average LIBOR rate of 1.24% plus a margin of 3.00% for LIBOR borrowings and the prime rate of 4.25% plus a margin of 2.00% on alternate base rate borrowings. At September 30, 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. The following table summarizes the debt covenant levels specified in the Credit Agreement as of September 30, 2017:



		Senior Secured	Interest
Period Beginning	Leverage Ratio (1)	Leverage Ratio (1)	Coverage Ratio (2)
September 30, 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.

At September 30, 2017 our leverage ratio was approximately 5.42 to 1, our senior secured leverage ratio was approximately 0.75 to 1 and our interest coverage ratio was approximately 2.26 to 1.

At September 30, 2017, we were in compliance with the covenants under the Credit Agreement.

Senior Secured Notes

During the six months ended September 30, 2017, we repurchased $55.0 million of our senior secured notes for an aggregate purchase price of $57.2 million (excluding payments of accrued interest), and recorded a loss on the early extinguishment of $3.2 million (net of $1.0 million of debt issuance costs.) Following the repurchase, semi-annual installment payments will be $19.5 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022.

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.

At September 30, 2017, we were in compliance with the covenants under the note purchase agreement for our senior secured notes.

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

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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 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.

Repurchases

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



	Three Months Ended		Six Months Ended
	September 30,		September 30,
	2017		2017
	(in thousands)
2019 Notes
Notes repurchased	$	1,475	$	18,677
Cash paid (excluding payments of accrued interest)	$	1,449	$	18,641
Gain (loss) on early extinguishment of debt (1)	$	15	$	(102	)

2023 Notes
Notes repurchased	$	26,457	$	26,457
Cash paid (excluding payments of accrued interest)	$	25,459	$	25,459
Gain on early extinguishment of debt (2)	$	595	$	595

2025 Notes
Notes repurchased	$	15,700	$	15,700
Cash paid (excluding payments of accrued interest)	$	14,108	$	14,108
Gain on early extinguishment of debt (3)	$	1,333	$	1,333


(1)	Gain (loss) on the early extinguishment of debt for the 2019 Notes during the three months and six months ended September 30, 2017 are net of debt issuance costs of less than $0.1 million and $0.1 million, respectively.


(2)	Gains on the early extinguishment of debt for the 2023 Notes during the three months and six months ended September 30, 2017 are net of debt issuance costs of $0.4 million and $0.4 million, respectively.


(3)	Gains on the early extinguishment of debt for the 2025 Notes during the three months and six months ended September 30, 2017 are net of debt issuance costs of $0.3 million and $0.3 million, respectively.

At September 30, 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 a principal balance of $6.5 million at September 30, 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 a principal balance of $6.3 million at September 30, 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 September 30, 2017:



Fiscal Year Ending March 31,	Revolving Credit Facility		Senior Secured Notes		Senior Unsecured Notes		Other Long-Term Debt		Total
	(in thousands)
2018 (six months)	$	—	$	19,500	$	—	$	1,793	$	21,293
2019	—		39,000		—		2,895		41,895
2020	—		39,000		360,781		2,285		402,066
2021	—		39,000		—		5,450		44,450
2022	971,500		39,000		367,048		274		1,377,822
Thereafter	—		19,500		1,157,843		59		1,177,402
Total	$	971,500	$	195,000	$	1,885,672	$	12,756	$	3,064,928

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 September 30, 2017 includes a liability, measured on an undiscounted basis, of $2.1 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	(233		)
Accretion expense	511
Balance at September 30, 2017	$	8,902

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 September 30, 2017 (in thousands):



Fiscal Year Ending March 31,
2018 (six months)	$	71,787
2019	120,589
2020	107,255
2021	94,118
2022	65,985
Thereafter	93,844
Total	$	553,578

Rental expense relating to operating leases was $32.5 million and $27.0 million during the three months ended September 30, 2017 and 2016, respectively, and $63.8 million and $56.9 million during the six months ended September 30, 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. 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 September 30, 2017 (in thousands):



Fiscal Year Ending March 31,
2018 (six months)	$	26,001
2019	52,042
2020	42,351
Total	$	120,394

Construction Commitments

At September 30, 2017, we had construction commitments of $24.5 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 September 30, 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 (six months)	$	161,432	3,330	$	44,816	58,925
2019	—		—	1,340		2,268
Total	$	161,432	3,330	$	46,156	61,193

Index-Price Commodity Purchase Commitments:
2018 (six months)	$	576,009	12,143	$	563,817	624,075
2019	524,256		11,595	37,426		45,736
2020	412,569		9,324	—		—
2021	161,485		3,833	—		—
2022	95,761		2,247	—		—
Total	$	1,770,080	39,142	$	601,243	669,811


(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 September 30, 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 (six months)	$	204,579	4,196	$	137,467	159,427
2019	—		—	7,209		9,827
2020	—		—	163		215
Total	$	204,579	4,196	$	144,839	169,469

Index-Price Commodity Sale Commitments:
2018 (six months)	$	480,203	9,507	$	522,430	478,300
2019	94,366		1,825	6,163		6,981
2020	54,526		1,070	—		—
Total	$	629,095	12,402	$	528,593	485,281

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 $28.1 million of our prepaid expenses and other current assets and $28.2 million of our accrued expenses and other payables at September 30, 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 converted to common units during the six months ended September 30, 2017, we issued 333 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 September 30, 2017, we repurchased 1,193,635 common units for an aggregate price of $11.2 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 three 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

Class A Convertible Preferred Units

On April 21, 2016, we received net proceeds $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 $4.0 million and $2.2 million during the three months ended September 30, 2017 and 2016, respectively, and $7.2 million and $3.8 million during the six months ended September 30, 2017 and 2016, respectively.

The holders of the warrants may convert 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 six months ended September 30, 2017, 607,653 warrants were converted to 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 September 30, 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 three 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

Class B Preferred Units

During the six months ended September 30, 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 $202.8 million (net of the underwriters’ discount of $6.6 million and offering costs of $0.6 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 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.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Distributions on the Class B Preferred Units are payable on the 15th day of each January, April, July and October of each year (beginning on October 15, 2017) 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, for which the amount is included in accrued expenses and other payables in our unaudited condensed consolidated balance sheet at September 30, 2017. The distribution was paid to the holders of the Class B Preferred Units on October 16, 2017.

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. Upon the occurrence of a change in control, we may redeem the Class B Preferred Units.

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 six months ended September 30, 2017, and approximately $134.7 million remained available for sale under the ATM Program at September 30, 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 six months ended September 30, 2017:



Unvested Service Award units at March 31, 2017	2,708,500
Units granted	137,921
Units vested and issued	(956,821	)
Units forfeited	(51,300	)
Unvested Service Award units at September 30, 2017	1,838,300

In connection with the vesting of certain restricted units during the six months ended September 30, 2017, we canceled 37,554 of the newly-vested common units in satisfaction of $0.5 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.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

The following table summarizes the scheduled vesting of our unvested Service Award units at September 30, 2017:



Fiscal Year Ending March 31,
2018 (six months)		—
2019		919,350
2020		914,450
2021		4,500
Total		1,838,300

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. During the three months ended September 30, 2017 and 2016, we recorded compensation expense related to Service Award units of $3.3 million and $25.8 million, respectively. During the six months ended September 30, 2017 and 2016, we recorded compensation expense related to Service Award units of $8.6 million and $46.7 million, respectively.

Of the restricted units granted and vested during the six months ended September 30, 2017, 66,421 units were granted as a bonus for performance during the fiscal year ended March 31, 2017. We accrued expense of $0.9 million during the fiscal year ended March 31, 2017 as an estimate of the value of such bonus units that would be granted.

The following table summarizes the estimated future expense we expect to record on the unvested Service Award units at September 30, 2017 (in thousands):



Fiscal Year Ending March 31,
2018 (six months)	$	5,865
2019	10,697
2020	2,827
2021	13
Total	$	19,402

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 September 30, 2017, performance will be measured over the following periods:



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 six months ended September 30, 2017:



Unvested Performance Award units at March 31, 2017	1,189,000
Units forfeited	(404,000	)
Unvested Performance Award units at September 30, 2017	785,000

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.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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 September 30, 2017 and 2016, we recorded compensation expense related to Performance Award units of $1.3 million and $1.6 million, respectively. During the six months ended September 30, 2017 and 2016, we recorded compensation expense related to Performance Awards units of $3.4 million and $3.1 million, respectively.

The following table summarizes the estimated future expense we expect to record on the unvested Performance Award units at September 30, 2017 (in thousands):



Fiscal Year Ending March 31,
2018 (six months)	$	2,635
2019	3,167
2020	642
Total	$	6,444

At September 30, 2017, approximately 3.2 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.

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:



	September 30, 2017						March 31, 2017
	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
	(in thousands)
Level 1 measurements	$	17,434		$	(39,361	)	$	2,590		$	(21,113	)
Level 2 measurements	29,080			(30,511		)	38,729			(27,799		)
	46,514			(69,872		)	41,319			(48,912		)

Netting of counterparty contracts (1)	(11,127		)	11,127			(1,508		)	1,508
Net cash collateral (held) provided	(6,284		)	27,774			(1,035		)	19,604
Commodity derivatives	$	29,103		$	(30,971	)	$	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.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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:



	September 30, 2017			March 31, 2017
	(in thousands)
Prepaid expenses and other current assets	$	29,005		$	38,711
Other noncurrent assets	98			65
Accrued expenses and other payables	(28,942		)	(27,622		)
Other noncurrent liabilities	(2,029		)	(178		)
Net commodity derivative (liability) asset	$	(1,868	)	$	10,976

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 September 30, 2017:
Cross-commodity (1)	October 2017–March 2018	(225	)	$	(1,372	)
Crude oil fixed-price (2)	October 2017–December 2019	(1,442	)	(3,005		)
Propane fixed-price (2)	October 2017–December 2018	498		6,165
Refined products fixed-price (2)	October 2017–January 2020	(1,976	)	(18,212		)
Refined products index (2)	October 2017–December 2017	(6	)	(12		)
Other	October 2017–March 2022			(6,922		)
				(23,358		)
Net cash collateral provided				21,490
Net commodity derivative liability				$	(1,868	)

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 six months ended September 30, 2017, we recorded a net loss of $71.4 million and $34.9 million, respectively, and during the three months and six months ended September 30, 2016, we recorded a net gain of $14.7 million and a net loss of $45.0 million, respectively, from our commodity derivatives to cost of sales in our unaudited condensed consolidated statements of operations.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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 September 30, 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.

Interest Rate Risk

Fair Value of Fixed-Rate Notes

The following table provides fair value estimates of our fixed-rate notes at September 30, 2017 (in thousands):



Senior secured notes	$	201,715
Senior unsecured notes:
5.125% Notes due 2019	$	360,673
6.875% Notes due 2021	$	366,938
7.500% Notes due 2023	$	670,605
6.125% Notes due 2025	$	451,004

For the senior secured notes, the fair value estimate was developed using observed yields on publicly traded notes issued by us, adjusted for differences in the key terms of those notes and the key terms of our notes (examples include differences in the tenor of the debt, credit standing of the issuer, whether the notes are publicly traded, and whether the notes are secured or unsecured). This fair value estimate would be classified as Level 3 in the fair value hierarchy. 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 September 30,						Six Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Revenues:
Crude Oil Logistics:
Crude oil sales	$	410,274		$	341,981		$	890,559		$	756,600
Crude oil transportation and other	29,315			9,172			56,301			22,106
Elimination of intersegment sales	(2,567		)	(1,268		)	(4,923		)	(2,870		)
Total Crude Oil Logistics revenues	437,022			349,885			941,937			775,836
Water Solutions:
Service fees	35,282			28,528			68,603			54,225
Recovered hydrocarbons	10,446			5,681			20,406			12,877
Other revenues	5,304			5,524			8,990			8,384
Total Water Solutions revenues	51,032			39,733			97,999			75,486
Liquids:
Propane sales	193,588			101,613			330,448			198,084
Butane sales	111,545			66,680			179,777			121,255
Other product sales	102,409			69,020			186,712			128,180
Other revenues	3,928			8,075			9,940			15,222
Elimination of intersegment sales	(18,347		)	(11,128		)	(35,940		)	(23,432		)
Total Liquids revenues	393,123			234,260			670,937			439,309
Retail Propane:
Propane sales	48,004			36,170			96,636			77,811
Distillate sales	6,676			5,589			16,231			16,044
Other revenues	10,043			9,331			18,936			17,638
Elimination of intersegment sales	(23		)	—			(31		)	(16		)
Total Retail Propane revenues	64,700			51,090			131,772			111,477
Refined Products and Renewables:
Refined products sales	2,874,268			2,274,715			5,647,875			4,151,572
Renewables sales	102,964			95,830			213,930			202,312
Service fees	50			(121		)	168			11,145
Elimination of intersegment sales	(76		)	(102		)	(130		)	(144		)
Total Refined Products and Renewables revenues	2,977,206			2,370,322			5,861,843			4,364,885
Corporate and Other	246			248			407			515
Total revenues	$	3,923,329		$	3,045,538		$	7,704,895		$	5,767,508
Depreciation and Amortization:
Crude Oil Logistics	$	20,958		$	9,025		$	41,793		$	17,993
Water Solutions	25,253			25,129			49,261			49,563
Liquids	6,141			4,425			12,471			8,874
Retail Propane	11,613			10,705			23,075			20,392
Refined Products and Renewables	324			416			648			833
Corporate and Other	919			903			1,839			1,854
Total depreciation and amortization	$	65,208		$	50,603		$	129,087		$	99,509
Operating Income (Loss):
Crude Oil Logistics	$	1,196		$	(19,039	)	$	5,553		$	(19,664	)
Water Solutions	(7,548		)	(4,430		)	(8,702		)	75,034
Liquids	(118,107		)	8,384			(126,879		)	8,327
Retail Propane	(9,226		)	(8,717		)	(15,094		)	(11,219		)
Refined Products and Renewables	21,042			11,387			35,538			161,156
Corporate and Other	(16,459		)	(23,413		)	(34,185		)	(55,562		)
Total operating (loss) income	$	(129,102	)	$	(35,828	)	$	(143,769	)	$	158,072

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 September 30,				Six Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Crude Oil Logistics	$	4,663	$	32,397	$	11,721	$	104,702
Water Solutions	15,035		25,237		34,440		68,353
Liquids	1,138		6,693		1,680		13,161
Retail Propane	30,869		71,425		34,715		77,974
Refined Products and Renewables	—		1,143		—		1,167
Corporate and Other	440		614		709		1,732
Total	$	52,145	$	137,509	$	83,265	$	267,089

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:



	September 30, 2017		March 31, 2017
	(in thousands)
Long-lived assets, net:
Crude Oil Logistics	$	1,677,505	$	1,724,805
Water Solutions	1,244,035		1,261,944
Liquids	490,586		619,204
Retail Propane	561,271		547,960
Refined Products and Renewables	212,209		215,637
Corporate and Other	34,830		36,395
Total	$	4,220,436	$	4,405,945

Total assets:
Crude Oil Logistics	$	2,377,973	$	2,538,768
Water Solutions	1,302,896		1,301,415
Liquids	861,050		767,597
Retail Propane	630,567		622,859
Refined Products and Renewables	960,002		988,073
Corporate and Other	77,170		101,667
Total	$	6,209,658	$	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 six months ended September 30, 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 September 30,				Six Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Sales to SemGroup	$	107	$	3,513	$	230	$	3,584
Purchases from SemGroup	$	1,911	$	1,938	$	2,928	$	3,963
Sales to equity method investees	$	98	$	95	$	196	$	500
Purchases from equity method investees	$	20,563	$	27,345	$	48,469	$	57,992
Sales to entities affiliated with management	$	57	$	75	$	140	$	152
Purchases from entities affiliated with management	$	1,150	$	3,493	$	1,347	$	11,736

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



	September 30, 2017		March 31, 2017
	(in thousands)
Receivables from SemGroup	$	2,881	$	6,668
Receivables from equity method investees	17		15
Receivables from entities affiliated with management	20		28
Total	$	2,918	$	6,711

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



	September 30, 2017		March 31, 2017
	(in thousands)
Payables to SemGroup	$	4,099	$	6,571
Payables to equity method investees	643		1,306
Payables to entities affiliated with management	7		41
Total	$	4,749	$	7,918

At September 30, 2017 and March 31, 2017, we had a loan receivable of $4.2 million and $3.2 million, respectively, from Victory Propane, LLC, an equity method investee (see Note 2), 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.

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.

Note 14—Subsequent Events

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 business for $200 million in cash, adjusted for working capital at closing. We will retain this business through closing, which is scheduled for March 31, 2018 and will also retain all profits generated through the closing date. 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. Closing of the sale is subject to regulatory and other customary closing conditions.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

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)



	September 30, 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	$	6,569	$	—	$	10,686		$	1,152		$	—		$	18,407
Accounts receivable-trade, net of allowance for doubtful accounts	—		—		838,360			3,285			—			841,645
Accounts receivable-affiliates	—		—		2,918			—			—			2,918
Inventories	—		—		570,017			716			—			570,733
Prepaid expenses and other current assets	—		—		112,120			397			—			112,517
Total current assets	6,569		—		1,534,101			5,550			—			1,546,220
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,736,522			31,963			—			1,768,485
GOODWILL	—		—		1,326,659			12,757			—			1,339,416
INTANGIBLE ASSETS, net of accumulated amortization	—		—		1,098,906			13,629			—			1,112,535
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		198,281			—			—			198,281
NET INTERCOMPANY RECEIVABLES (PAYABLES)	2,477,069		—		(2,455,724		)	(21,345		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,652,951		—		23,990			—			(1,676,941		)	—
LOAN RECEIVABLE-AFFILIATE	—		—		4,160			—			—			4,160
OTHER NONCURRENT ASSETS	—		—		240,561			—			—			240,561
Total assets	$	4,136,589	$	—	$	3,707,456		$	42,554		$	(1,676,941	)	$	6,209,658
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	—	$	—	$	634,344		$	968		$	—		$	635,312
Accounts payable-affiliates	1		—		4,748			—			—			4,749
Accrued expenses and other payables	44,890		—		181,323			856			—			227,069
Advance payments received from customers	—		—		79,555			823			—			80,378
Current maturities of long-term debt	39,000		—		2,993			380			—			42,373
Total current liabilities	83,891		—		902,963			3,027			—			989,881
LONG-TERM DEBT, net of debt issuance costs and current maturities	2,012,578		—		979,965			918			—			2,993,461
OTHER NONCURRENT LIABILITIES	—		—		171,576			4,309			—			175,885
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS	71,009		—		—			—			—			71,009
REDEEMABLE NONCONTROLLING INTEREST	—		—		—			3,129			—			3,129
EQUITY:
Partners’ equity	1,969,111		—		1,654,991			31,394			(1,684,122		)	1,971,374
Accumulated other comprehensive loss	—		—		(2,039		)	(223		)	—			(2,262		)
Noncontrolling interests	—		—		—			—			7,181			7,181
Total equity	1,969,111		—		1,652,952			31,171			(1,676,941		)	1,976,293
Total liabilities and equity	$	4,136,589	$	—	$	3,707,456		$	42,554		$	(1,676,941	)	$	6,209,658

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 September 30, 2017
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated

REVENUES	$	—		$	—	$	3,918,880		$	5,356		$	(907	)	$	3,923,329
COST OF SALES	—			—		3,768,306			3,322			(907		)	3,770,721
OPERATING COSTS AND EXPENSES:
Operating	—			—		74,404			1,566			—			75,970
General and administrative	—			—		23,353			127			—			23,480
Depreciation and amortization	—			—		64,499			709			—			65,208
Loss on disposal or impairment of assets, net	—			—		110,952			500			—			111,452
Revaluation of liabilities	—			—		5,600			—			—			5,600
Operating Loss	—			—		(128,234		)	(868		)	—			(129,102		)
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		2,028			—			—			2,028
Interest expense	(37,219		)	—		(12,992		)	(227		)	205			(50,233		)
Gain on early extinguishment of liabilities, net	1,943			—		—			—			—			1,943
Other income, net	—			—		2,084			17			(205		)	1,896
Loss Before Income Taxes	(35,276		)	—		(137,114		)	(1,078		)	—			(173,468		)
INCOME TAX EXPENSE	—			—		(111		)	—			—			(111		)
EQUITY IN NET LOSS OF CONSOLIDATED SUBSIDIARIES	(138,095		)	—		(870		)	—			138,965			—
Net Loss	(173,371		)	—		(138,095		)	(1,078		)	138,965			(173,579		)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(80		)	(80		)
LESS: NET LOSS ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS												288			288
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(16,098		)	(16,098		)
LESS: NET LOSS ALLOCATED TO GENERAL PARTNER												154			154
NET LOSS ALLOCATED TO COMMON UNITHOLDERS	$	(173,371	)	$	—	$	(138,095	)	$	(1,078	)	$	123,229		$	(189,315	)

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 September 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated

REVENUES	$	—		$	—	$	3,034,053		$	12,118		$	(633	)	$	3,045,538
COST OF SALES	—			—		2,928,036			1,327			(633		)	2,928,730
OPERATING COSTS AND EXPENSES:
Operating	—			—		68,750			4,505			—			73,255
General and administrative	—			—		27,686			240			—			27,926
Depreciation and amortization	—			—		47,740			2,863			—			50,603
Loss (gain) on disposal or impairment of assets, net	—			—		896			(44		)	—			852
Operating (Loss) Income	—			—		(39,055		)	3,227			—			(35,828		)
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		53			—			—			53
Interest expense	(16,364		)	—		(16,870		)	(291		)	83			(33,442		)
Gain on early extinguishment of liabilities, net	—			—		938			—			—			938
Other income, net	—			—		2,154			10			(83		)	2,081
(Loss) Income Before Income Taxes	(16,364		)	—		(52,780		)	2,946			—			(66,198		)
INCOME TAX EXPENSE	—			—		(460		)	—			—			(460		)
EQUITY IN NET (LOSS) INCOME OF CONSOLIDATED SUBSIDIARIES	(50,235		)	—		3,005			—			47,230			—
Net (Loss) Income	(66,599		)	—		(50,235		)	2,946			47,230			(66,658		)
LESS: NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS												59			59
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(8,668		)	(8,668		)
LESS: NET LOSS ALLOCATED TO GENERAL PARTNER												45			45
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$	(66,599	)	$	—	$	(50,235	)	$	2,946		$	38,666		$	(75,222	)

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statement of Operations

(in Thousands)



	Six Months Ended September 30, 2017
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated

REVENUES	$	—		$	—	$	7,696,763		$	9,443		$	(1,311	)	$	7,704,895
COST OF SALES	—			—		7,409,800			4,340			(1,311		)	7,412,829
OPERATING COSTS AND EXPENSES:
Operating	—			—		148,908			3,531			—			152,439
General and administrative	—			—		48,157			314			—			48,471
Depreciation and amortization	—			—		126,932			2,155			—			129,087
Loss on disposal or impairment of assets, net	—			—		99,073			1,165			—			100,238
Revaluation of liabilities	—			—		5,600			—			—			5,600
Operating Loss	—			—		(141,707		)	(2,062		)	—			(143,769		)
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		3,844			—			—			3,844
Interest expense	(75,590		)	—		(23,824		)	(453		)	408			(99,459		)
Loss on early extinguishment of liabilities, net	(1,338		)	—		—			—			—			(1,338		)
Other income, net	—			—		4,358			56			(408		)	4,006
Loss Before Income Taxes	(76,928		)	—		(157,329		)	(2,459		)	—			(236,716		)
INCOME TAX EXPENSE	—			—		(570		)	—			—			(570		)
EQUITY IN NET LOSS OF CONSOLIDATED SUBSIDIARIES	(159,805		)	—		(1,906		)	—			161,711			—
Net Loss	(236,733		)	—		(159,805		)	(2,459		)	161,711			(237,286		)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(132		)	(132		)
LESS: NET LOSS ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS												685			685
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(25,782		)	(25,782		)
LESS: NET LOSS ALLOCATED TO GENERAL PARTNER												194			194
LESS: REPURCHASE OF WARRANTS												(349		)	(349		)
NET LOSS ALLOCATED TO COMMON UNITHOLDERS	$	(236,733	)	$	—	$	(159,805	)	$	(2,459	)	$	136,327		$	(262,670	)

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statement of Operations

(in Thousands)



	Six Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated

REVENUES	$	—		$	—	$	5,749,034		$	19,469		$	(995	)	$	5,767,508
COST OF SALES	—			—		5,493,864			2,301			(995		)	5,495,170
OPERATING COSTS AND EXPENSES:
Operating	—			—		139,631			8,796			—			148,427
General and administrative	—			—		69,312			485			—			69,797
Depreciation and amortization	—			—		94,049			5,460			—			99,509
Gain on disposal or impairment of assets, net	—			—		(203,443		)	(24		)	—			(203,467		)
Operating Income	—			—		155,621			2,451			—			158,072
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		447			—			—			447
Revaluation of investments	—			—		(14,365		)	—			—			(14,365		)
Interest expense	(32,690		)	—		(30,898		)	(453		)	161			(63,880		)
Gain on early extinguishment of liabilities, net	8,614			—		22,276			—			—			30,890
Other income, net	—			—		5,990			24			(161		)	5,853
(Loss) Income Before Income Taxes	(24,076		)	—		139,071			2,022			—			117,017
INCOME TAX EXPENSE	—			—		(922		)	—			—			(922		)
EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES	134,397			—		(3,752		)	—			(130,645		)	—
Net Income	110,321			—		134,397			2,022			(130,645		)	116,095
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(5,774		)	(5,774		)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS												(12,052		)	(12,052		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(158		)	(158		)
NET INCOME ALLOCATED TO COMMON UNITHOLDERS	$	110,321		$	—	$	134,397		$	2,022		$	(148,629	)	$	98,111

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 September 30, 2017
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
Net loss	$	(173,371	)	$	—	$	(138,095	)	$	(1,078	)	$	138,965	$	(173,579	)
Other comprehensive loss	—			—		(48		)	(11		)	—		(59		)
Comprehensive loss	$	(173,371	)	$	—	$	(138,143	)	$	(1,089	)	$	138,965	$	(173,638	)



	Three Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments		Consolidated
Net (loss) income	$	(66,599	)	$	—	$	(50,235	)	$	2,946	$	47,230	$	(66,658	)
Other comprehensive loss	—			—		(333		)	—		—		(333		)
Comprehensive (loss) income	$	(66,599	)	$	—	$	(50,568	)	$	2,946	$	47,230	$	(66,991	)



	Six Months Ended September 30, 2017
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
Net loss	$	(236,733	)	$	—	$	(159,805	)	$	(2,459	)	$	161,711	$	(237,286	)
Other comprehensive loss	—			—		(412		)	(22		)	—		(434		)
Comprehensive loss	$	(236,733	)	$	—	$	(160,217	)	$	(2,481	)	$	161,711	$	(237,720	)



	Six Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net income	$	110,321	$	—	$	134,397		$	2,022		$	(130,645	)	$	116,095
Other comprehensive loss	—		—		(475		)	(10		)	—			(485		)
Comprehensive income	$	110,321	$	—	$	133,922		$	2,012		$	(130,645	)	$	115,610

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statement of Cash Flows

(in Thousands)



	Six Months Ended September 30, 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	$	43,235		$	—	$	(67,691	)	$	34,410		$	9,954
INVESTING ACTIVITIES:
Capital expenditures	—			—		(55,666		)	(802		)	(56,468		)
Acquisitions, net of cash acquired	—			—		(48,034		)	(400		)	(48,434		)
Cash flows from settlements of commodity derivatives	—			—		(22,039		)	—			(22,039		)
Proceeds from sales of assets	—			—		24,586			—			24,586
Investments in unconsolidated entities	—			—		(14,150		)	—			(14,150		)
Distributions of capital from unconsolidated entities	—			—		4,378			—			4,378
Payments on loan for natural gas liquids facility	—			—		4,875			—			4,875
Loan to affiliate	—			—		(960		)	—			(960		)
Net cash used in investing activities	—			—		(107,010		)	(1,202		)	(108,212		)
FINANCING ACTIVITIES:
Proceeds from borrowings under Revolving Credit Facility	—			—		814,500			—			814,500
Payments on Revolving Credit Facility	—			—		(657,500		)	—			(657,500		)
Repurchase of senior secured and senior unsecured notes	(115,407		)	—		—			—			(115,407		)
Payments on other long-term debt	—			—		(2,973		)	(190		)	(3,163		)
Debt issuance costs	(670		)	—		(1,804		)	—			(2,474		)
Contributions from noncontrolling interest owners, net	—			—		—			23			23
Distributions to general and common unit partners and preferred unitholders	(107,389		)	—		—			—			(107,389		)
Distributions to noncontrolling interest owners	—			—		—			(3,082		)	(3,082		)
Proceeds from sale of preferred units, net of offering costs	202,755			—		—			—			202,755
Repurchase of warrants	(10,549		)	—		—			—			(10,549		)
Common unit repurchases	(11,663		)	—		—			—			(11,663		)
Payments for settlement and early extinguishment of liabilities	—			—		(1,650		)	—			(1,650		)
Net changes in advances with consolidated entities	—			—		31,911			(31,911		)	—
Net cash (used in) provided by financing activities	(42,923		)	—		182,484			(35,160		)	104,401
Net increase (decrease) in cash and cash equivalents	312			—		7,783			(1,952		)	6,143
Cash and cash equivalents, beginning of period	6,257			—		2,903			3,104			12,264
Cash and cash equivalents, end of period	$	6,569		$	—	$	10,686		$	1,152		$	18,407

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

Unaudited Condensed Consolidating Statement of Cash Flows

(in Thousands)



	Six Months Ended September 30, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash used in operating activities	$	(31,541	)	$	—	$	(11,229	)	$	(12,107	)	$	(54,877	)
INVESTING ACTIVITIES:
Capital expenditures	—			—		(200,286		)	(1,347		)	(201,633		)
Acquisitions, net of cash acquired	—			—		(113,297		)	—			(113,297		)
Cash flows from settlements of commodity derivatives	—			—		(25,015		)	—			(25,015		)
Proceeds from sales of assets	—			—		379			17			396
Proceeds from sale of TLP common units	—			—		112,370			—			112,370
Distributions of capital from unconsolidated entities	—			—		5,233			—			5,233
Payments on loan for natural gas liquids facility	—			—		4,324			—			4,324
Loan to affiliate	—			—		(1,700		)	—			(1,700		)
Payments on loan to affiliate	—			—		655			—			655
Payment to terminate development agreement	—			—		(16,875		)	—			(16,875		)
Net cash used in investing activities	—			—		(234,212		)	(1,330		)	(235,542		)
FINANCING ACTIVITIES:
Proceeds from borrowings under Revolving Credit Facility	—			—		770,000			—			770,000
Payments on Revolving Credit Facility	—			—		(595,500		)	—			(595,500		)
Repurchase of senior unsecured notes	(15,129		)	—		—			—			(15,129		)
Payments on other long-term debt	—			—		(4,080		)	(343		)	(4,423		)
Debt issuance costs	(255		)	—		(65		)	—			(320		)
Contributions from general partner	59			—		—			—			59
Contributions from noncontrolling interest owners, net	(501		)	—		—			966			465
Distributions to general and common unit partners and preferred unitholders	(83,707		)	—		—			—			(83,707		)
Distributions to noncontrolling interest owners	—			—		—			(2,750		)	(2,750		)
Proceeds from sale of preferred units, net of offering costs	235,018			—		—			—			235,018
Proceeds from sale of common units, net of offering costs	9,383			—		—			—			9,383
Payments for settlement and early extinguishment of liabilities	—			—		(27,406		)	—			(27,406		)
Net changes in advances with consolidated entities	(128,960		)	—		113,907			15,053			—
Other	—			—		(20		)	—			(20		)
Net cash provided by financing activities	15,908			—		256,836			12,926			285,670
Net (decrease) increase in cash and cash equivalents	(15,633		)	—		11,395			(511		)	(4,749		)
Cash and cash equivalents, beginning of period	25,749			—		784			1,643			28,176
Cash and cash equivalents, end of period	$	10,116		$	—	$	12,179		$	1,132		$	23,427

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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 six months ended September 30, 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 September 30, 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 September 30,						Six Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Total revenues	$	3,923,329		$	3,045,538		$	7,704,895		$	5,767,508
Total cost of sales	3,770,721			2,928,730			7,412,829			5,495,170
Operating expenses	75,970			73,255			152,439			148,427
General and administrative expense	23,480			27,926			48,471			69,797
Depreciation and amortization	65,208			50,603			129,087			99,509
Loss (gain) on disposal or impairment of assets, net	111,452			852			100,238			(203,467		)
Revaluation of liabilities	5,600			—			5,600			—
Operating (loss) income	(129,102		)	(35,828		)	(143,769		)	158,072
Equity in earnings of unconsolidated entities	2,028			53			3,844			447
Revaluation of investments	—			—			—			(14,365		)
Interest expense	(50,233		)	(33,442		)	(99,459		)	(63,880		)
Gain (loss) on early extinguishment of liabilities, net	1,943			938			(1,338		)	30,890
Other income, net	1,896			2,081			4,006			5,853
(Loss) income before income taxes	(173,468		)	(66,198		)	(236,716		)	117,017
Income tax expense	(111		)	(460		)	(570		)	(922		)
Net (loss) income	(173,579		)	(66,658		)	(237,286		)	116,095
Less: Net (income) loss attributable to noncontrolling interests	(80		)	59			(132		)	(5,774		)
Less: Net loss attributable to redeemable noncontrolling interests	288			—			685			—
Net (loss) income attributable to NGL Energy Partners LP	(173,371		)	(66,599		)	(236,733		)	110,321
Less: Distributions to preferred unitholders	(16,098		)	(8,668		)	(25,782		)	(12,052		)
Less: Net loss (income) allocated to general partner	154			45			194			(158		)
Less: Repurchase of warrants	—			—			(349		)	—
Net (loss) income allocated to common unitholders	$	(189,315	)	$	(75,222	)	$	(262,670	)	$	98,111

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 six months ended September 30, 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

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 (as defined herein), provides for an increase in interest charged if our leverage ratio exceeds certain predetermined levels and restricts us from increasing our distribution rate. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further description.

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Repurchases of Senior Unsecured Notes

During the three months ended September 30, 2017, we repurchased $1.5 million of the 5.125% senior notes due 2019 (the “2019 Notes”), $26.5 million of the 7.50% senior notes due 2023 (the “2023 Notes”), and $15.7 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.

Common Unit Repurchase Program

Acquisitions

As discussed below, we completed numerous acquisitions during the fiscal year ended March 31, 2017 and the six months ended September 30, 2017. These acquisitions impact the comparability of our results of operations between our current and prior fiscal years.

During the six months ended September 30, 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 four retail propane businesses. See Note 4 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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Segment Operating Results for the Three Months Ended September 30, 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 September 30,
	2017			2016			Change
	(in thousands, except per barrel amounts)
Revenues:
Crude oil sales	$	410,274		$	341,981		$	68,293
Crude oil transportation and other	29,315			9,172			20,143
Total revenues (1)	439,589			351,153			88,436
Expenses:
Cost of sales	403,737			341,786			61,951
Operating expenses	12,198			9,708			2,490
General and administrative expenses	1,657			1,196			461
Depreciation and amortization expense	20,958			9,025			11,933
(Gain) loss on disposal or impairment of assets, net	(157		)	8,477			(8,634		)
Total expenses	438,393			370,192			68,201
Segment operating income (loss)	$	1,196		$	(19,039	)	$	20,235

Crude oil sold (barrels)	8,562			7,770			792
Crude oil transported on owned pipelines (barrels)	8,182			—			8,182
Crude oil storage capacity - owned and leased (barrels) (2)	6,159			6,355			(196		)
Crude oil storage capacity sub-leased to third parties (barrels) (2)	700			2,000			(1,300		)
Crude oil inventory (barrels) (2)	1,682			1,982			(300		)
Crude oil sold ($/barrel)	$	47.918		$	44.013		$	3.905
Cost per crude oil sold ($/barrel)	$	47.155		$	43.988		$	3.167
Crude oil product margin ($/barrel)	$	0.763		$	0.025		$	0.738


(1)	Revenues include $2.6 million and $1.3 million of intersegment sales during the three months ended September 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of September 30, 2017 and September 30, 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 September 30, 2017, compared to the three months ended September 30, 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 this lower price environment to support our various pipeline, terminal and transportation assets.

Crude Oil Transportation and Other Revenues. The increase was due primarily to our Grand Mesa Pipeline becoming operational on November 1, 2016 with revenues of $19.1 million and higher revenues in our trucking and barge operations during the three months ended September 30, 2017, due to an increase in demand for transportation services, compared to the three months ended September 30, 2016, 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 September 30, 2017, compared to the three months ended September 30, 2016.

Cost of Sales. The increase was due primarily to an increase in crude oil prices during the three months ended September 30, 2017, compared to the three months ended September 30, 2016. Our cost of sales during the three months ended September 30, 2017 was increased by $0.2 million of net realized losses on derivatives and $2.2 million of net unrealized losses on derivatives. Our cost of sales during the three months ended September 30, 2016 was reduced by $2.7 million of net realized gains on derivatives and increased by $1.6 million of net unrealized losses on derivatives.

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Operating and General and Administrative Expenses. The increase was due primarily to our Grand Mesa Pipeline project becoming operational on November 1, 2016. During the three months ended September 30, 2017, we incurred expenses of $3.7 million related to Grand Mesa. This increase was partially offset by lower repair and maintenance expense related to having a newer fleet of barges and the timing of repairs, lower repair and maintenance expense and lower insurance expense related to having a smaller fleet of trucks, and lower property taxes due to decreased inventory.

Depreciation and Amortization Expense. The increase was due primarily to our Grand Mesa Pipeline project becoming operational on November 1, 2016. During the three months ended September 30, 2017, we incurred depreciation and amortization expense of $10.6 million related to Grand Mesa. 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 September 30, 2017, we recorded a net gain of $0.2 million on the sales of excess pipe and certain other assets. During the three months ended September 30, 2016, we recorded a net loss of $4.8 million on the sales of certain assets and a loss of $3.7 million due to the write-down of certain other assets.

Water Solutions

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



	Three Months Ended September 30,
	2017			2016			Change
	(in thousands, except per barrel and per day amounts)
Revenues:
Service fees	$	35,282		$	28,528		$	6,754
Recovered hydrocarbons	10,446			5,681			4,765
Other revenues	5,304			5,524			(220		)
Total revenues	51,032			39,733			11,299
Expenses:
Cost of sales-derivative loss (gain)	2,240			(2,354		)	4,594
Cost of sales-other	434			547			(113		)
Operating expenses	23,488			20,227			3,261
General and administrative expenses	650			625			25
Depreciation and amortization expense	25,253			25,129			124
Loss (gain) on disposal or impairment of assets, net	915			(11		)	926
Revaluation of liabilities	5,600			—			5,600
Total expenses	58,580			44,163			14,417
Segment operating loss	$	(7,548	)	$	(4,430	)	$	(3,118	)

Wastewater processed (barrels per day)
Eagle Ford Basin	209,792			201,390			8,402
Permian Basin	273,290			201,149			72,141
DJ Basin	108,952			62,641			46,311
Other Basins	63,443			37,559			25,884
Total	655,477			502,739			152,738
Solids processed (barrels per day)	5,794			2,541			3,253
Skim oil sold (barrels per day)	2,618			1,549			1,069
Service fees for wastewater processed ($/barrel)	$	0.59		$	0.62		$	(0.03	)
Recovered hydrocarbons for wastewater processed ($/barrel)	$	0.17		$	0.12		$	0.05
Operating expenses for wastewater processed ($/barrel)	$	0.39		$	0.44		$	(0.05	)

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, from the prior year, in the basins in which we operate, particularly in the Permian Basin.

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

Other Revenues. Other revenues primarily include solids disposal revenues and water pipeline revenues. The decrease was due primarily to a decrease in freshwater revenues due to the sale of Grassland in November 2016 and lower revenues from trucking wastewater to our water solutions facilities in one basin due to a new water pipeline being placed into service during the three months ended September 30, 2017. These decreases were partially offset by an increase in volumes for solids disposal and water pipeline businesses.

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 September 30, 2017 included $0.8 million of net realized gains on derivatives and $3.0 million of net unrealized losses on derivatives. Our cost of sales during the three months ended September 30, 2016 included $2.2 million of net unrealized gains on derivatives and $0.2 million of net realized gains on derivatives.

Cost of Sales-Other. The decrease was due to lower trucking expenses to bring wastewater to our water solutions facilities in one basin due to a new water pipeline being placed into service during the three months ended September 30, 2017, partially offset by an increase in expenses for newly offered trucking services to bring wastewater to our water solutions facilities in another basin.

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

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

Loss (Gain) on Disposal or Impairment of Assets, Net. During the three months ended September 30, 2017, we recorded a net loss of $0.9 million on the sales of certain assets. During the three months ended September 30, 2016, we recorded a net gain of less than $0.1 million on the sales of certain assets.

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 three months ended September 30, 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:



	Three Months Ended September 30,
	2017			2016		Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	193,588		$	101,613	$	91,975
Cost of sales	176,363			96,663		79,700
Product margin	17,225			4,950		12,275

Butane sales:
Revenues (1)	111,545			66,680		44,865
Cost of sales	124,985			58,898		66,087
Product (loss) margin	(13,440		)	7,782		(21,222		)

Other product sales:
Revenues (1)	102,409			69,020		33,389
Cost of sales	93,884			61,214		32,670
Product margin	8,525			7,806		719

Other revenues:
Revenues (1)	3,928			8,075		(4,147		)
Cost of sales	684			3,636		(2,952		)
Product margin	3,244			4,439		(1,195		)

Expenses:
Operating expenses	8,510			11,608		(3,098		)
General and administrative expenses	1,281			543		738
Depreciation and amortization expense	6,141			4,425		1,716
Loss on disposal or impairment of assets, net	117,729			17		117,712
Total expenses	133,661			16,593		117,068
Segment operating (loss) income	$	(118,107	)	$	8,384	$	(126,491	)

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

Propane sold (gallons)	257,775			222,352		35,423
Propane sold ($/gallon)	$	0.751		$	0.457	$	0.294
Cost per propane sold ($/gallon)	$	0.684		$	0.435	$	0.249
Propane product margin ($/gallon)	$	0.067		$	0.022	$	0.045
Propane inventory (gallons) (2)	136,980			146,995		(10,015		)
Propane storage capacity sub-leased to third parties - leased and owned (gallons) (2)	33,495			33,264		231

Butane sold (gallons)	125,419			102,147		23,272
Butane sold ($/gallon)	$	0.889		$	0.653	$	0.236
Cost per butane sold ($/gallon)	$	0.997		$	0.577	$	0.420
Butane product margin ($/gallon)	$	(0.108	)	$	0.076	$	(0.184	)
Butane inventory (gallons) (2)	111,632			72,369		39,263
Butane storage capacity sub-leased to third parties - leased and owned (gallons) (2)	80,346			72,540		7,806

Other products sold (gallons)	102,009			86,817		15,192
Other products sold ($/gallon)	$	1.004		$	0.795	$	0.209
Cost per other products sold ($/gallon)	$	0.920		$	0.705	$	0.215
Other products product margin ($/gallon)	$	0.084		$	0.090	$	(0.006	)
Other products inventory (gallons) (2)	8,810			9,014		(204		)


(1)	Revenues include $18.3 million and $11.1 million of intersegment sales during the three months ended September 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of September 30, 2017 and September 30, 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 reduced by $5.8 million of net unrealized gains on derivatives and increased by less than $0.1 million of net realized losses on derivatives during the three months ended September 30, 2017. During the three months ended September 30, 2016, our cost of wholesale propane sales was reduced by $0.1 million of net unrealized gains on derivatives and increased by less than $0.1 million of net realized losses on derivatives.

Propane margins are higher due primarily to the increase in market prices outpacing the rise in 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 September 30, 2017 was increased by $18.2 million of net unrealized losses on derivatives, compared to an increase of $3.3 million of net unrealized losses on derivatives during the three months ended September 30, 2016. Additionally, our cost of butane sales was reduced by $0.6 million of net realized gains on derivatives and $0.6 million of net realized gains on derivatives during the three months ended September 30, 2017 and 2016, respectively.

Product margins per gallon of butane were lower during the three months ended September 30, 2017 than during the three months ended September 30, 2016 due primarily to the unrealized losses on derivatives noted above. The butane product margins, excluding the unrealized losses on derivatives, were $0.038 per gallon for the three months ended September 30, 2017.

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 increased by $0.3 million of net unrealized losses on derivatives and reduced by net realized gains on derivatives of $0.1 million during the three months ended September 30, 2017. Our cost of sales of other products during the three months ended September 30, 2016 was reduced by $0.7 million of net unrealized gains on derivatives and $0.1 million of net realized gains on derivatives.

Product margins during the three months ended September 30, 2017 were reduced due to an increase in unrecovered railcar fleet costs.

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

Operating and General and Administrative Expenses. This decrease was due primarily to lower compensation expense, $2.8 million of which resulted from a shift in the recording of compensation expense related to bonuses from the Liquids segment to “Corporate and Other” during the three months ended September 30, 2017. See further discussion within the “Corporate and Other” section below.

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.

Loss on Disposal or Impairment of Assets, Net. During the three months ended September 30, 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 three months ended September 30, 2017, we recorded a net loss of $0.9 million related to the retirement of assets. During the three months ended September 30, 2016, we recorded a net loss of less than $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 September 30,
	2017			2016			Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	48,004		$	36,170		$	11,834
Cost of sales	22,158			13,272			8,886
Product margin	25,846			22,898			2,948

Distillate sales:
Revenues (1)	6,676			5,589			1,087
Cost of sales	5,390			4,406			984
Product margin	1,286			1,183			103

Other revenues:
Revenues (1)	10,043			9,331			712
Cost of sales	3,772			3,013			759
Product margin	6,271			6,318			(47		)

Expenses:
Operating expenses	28,201			27,132			1,069
General and administrative expenses	2,322			1,344			978
Depreciation and amortization expense	11,613			10,705			908
Loss (gain) on disposal or impairment of assets, net	493			(65		)	558
Total expenses	42,629			39,116			3,513
Segment operating loss	$	(9,226	)	$	(8,717	)	$	(509	)

Propane sold (gallons)	28,182			23,745			4,437
Propane sold ($/gallon)	$	1.703		$	1.523		$	0.180
Cost per propane sold ($/gallon)	$	0.786		$	0.559		$	0.227
Propane product margin ($/gallon)	$	0.917		$	0.964		$	(0.047	)
Propane inventory (gallons) (2)	11,183			10,625			558

Distillates sold (gallons)	3,203			2,949			254
Distillates sold ($/gallon)	$	2.084		$	1.895		$	0.189
Cost per distillates sold ($/gallon)	$	1.683		$	1.494		$	0.189
Distillates product margin ($/gallon)	$	0.401		$	0.401		$	—
Distillates inventory (gallons) (2)	2,793			3,083			(290		)


(1)	Revenues include less than $0.1 million of intersegment sales during the three months ended September 30, 2017 that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of September 30, 2017 and September 30, 2016, respectively.

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.

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

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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 four retail propane businesses in the current year.

Depreciation and Amortization Expense. The increase was due primarily to the acquisition of four retail propane businesses during the previous fiscal year and four retail propane businesses in the current year.

Loss (Gain) on Disposal or Impairment of Assets, Net. Amounts represent 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 September 30,
	2017			2016			Change
	(in thousands, except per barrel amounts)
Refined products sales:
Revenues (1)	$	2,874,268		$	2,274,715		$	599,553
Cost of sales	2,854,907			2,265,182			589,725
Product margin	19,361			9,533			9,828

Renewables sales:
Revenues	102,964			95,830			7,134
Cost of sales	103,036			94,852			8,184
Product (loss) margin	(72		)	978			(1,050		)

Service fee revenues	50			(121		)	171

Expenses:
Operating expenses	3,338			4,341			(1,003		)
General and administrative expenses	2,163			1,809			354
Depreciation and amortization expense	324			416			(92		)
Gain on disposal or impairment of assets, net	(7,528		)	(7,563		)	35
Total income	(1,703		)	(997		)	(706		)
Segment operating income	$	21,042		$	11,387		$	9,655

Gasoline sold (barrels)	26,459			23,107			3,352
Diesel sold (barrels)	14,990			14,341			649
Ethanol sold (barrels)	978			1,035			(57		)
Biodiesel sold (barrels)	568			464			104
Refined products and renewables storage capacity - leased (barrels) (2)	9,070			7,645			1,425
Refined products and renewables storage capacity sub-leased to third parties (barrels) (2)	1,043			1,063			(20		)
Gasoline inventory (barrels) (2)	1,862			1,995			(133		)
Diesel inventory (barrels) (2)	1,148			2,339			(1,191		)
Ethanol inventory (barrels) (2)	513			372			141
Biodiesel inventory (barrels) (2)	375			260			115
Refined products sold ($/barrel)	$	69.345		$	60.743		$	8.602
Cost per refined products sold ($/barrel)	$	68.878		$	60.489		$	8.389
Refined products product margin ($/barrel)	$	0.467		$	0.254		$	0.213
Renewable products sold ($/barrel)	$	66.600		$	63.929		$	2.671
Cost per renewable products sold ($/barrel)	$	66.647		$	63.277		$	3.370
Renewable products product margin ($/barrel)	$	(0.047	)	$	0.652		$	(0.699	)


(1)	Revenues include $0.1 million and $0.1 million of intersegment sales during the three months ended September 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of September 30, 2017 and September 30, 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 increased volumes were due primarily to an expansion of our refined

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products operations, the continued demand for motor fuels and the Colonial Pipeline being down for maintenance for a portion of the prior year quarter. The margin was higher during the three months ended September 30, 2017 due primarily to an increase in Gulf Coast prices as a result of supply disruptions.

Renewables Revenues and Cost of Sales. The increases in revenues and cost of sales were due primarily to an increase in renewables prices and increased volumes. The margin was lower during the three months ended September 30, 2017 due primarily to unfavorable biodiesel margins.

Service Fee Revenues, Operating Expenses, General and Administrative Expenses. The changes were due primarily to the expiration of a transition services agreement in October 2016 related to the sale of all of the TransMontaigne Partners L.P. (“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 three months ended September 30, 2017, we recorded $7.5 million of the deferred gain from the sale of the general partner in 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 three months ended September 30, 2016, we recorded:


•	$7.5 million of the deferred gain from the sale of the general partner in 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); and


•	a gain of less than $0.1 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 September 30,
	2017			2016			Change
	(in thousands)
Other revenues	$	246		$	248		$	(2	)

Expenses:
Cost of sales	121			113			8
Operating expenses	258			239			19
General and administrative expenses	15,407			22,409			(7,002		)
Depreciation and amortization expense	919			903			16
Gain on disposal or impairment of assets, net	—			(3		)	3
Total expenses	16,705			23,661			(6,956		)
Operating loss	$	(16,459	)	$	(23,413	)	$	6,954

General and Administrative Expenses. The decrease during the three months ended September 30, 2017 was due primarily to lower incentive compensation expense.

The decrease in incentive compensation was primarily related to our service awards units. During the three months ended September 30, 2017, expense related to the service award units was $3.3 million, compared to $6.9 million during the three months ended September 30, 2016. During the three months ended September 30, 2017, the expense for the service award units was lower due to the cancellation of certain service awards in the prior year quarter for which the expense had to be accelerated, as well as 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. In addition, compensation expense of $2.8 million was shifted from our Liquids segment during the three months ended September 30, 2017 due to our expectation of paying these amounts in common units.

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Equity in Earnings of Unconsolidated Entities

The increase of $2.0 million during the three months ended September 30, 2017 was due primarily to increased earnings related to our investments in Glass Mountain Pipeline, LLC (“Glass Mountain”) and E Energy Adams, LLC.

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 $16.8 million during the three months ended September 30, 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.

Gain on Early Extinguishment of Liabilities, Net

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



	Three Months Ended September 30,
	2017		2016
	(in thousands)
Early extinguishment of long-term debt (1)	$	1,943	$	—
Release of contingent consideration liabilities (2)	—		938
Gain on early extinguishment of liabilities, net	$	1,943	$	938


(1)	During the three months ended September 30, 2017, this relates to gains on the early extinguishment of a portion of the 2019 Notes, the 2023 Notes and the 2025 Notes. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.


(2)	During the three months ended September 30, 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.

Other Income, Net

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



	Three Months Ended September 30,
	2017			2016
	(in thousands)
Interest income (1)	$	1,880		$	1,997
Crude oil marketing arrangement (2)	(1		)	(30		)
Other	17			114
Other income, net	$	1,896		$	2,081


(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.

Income Tax Expense

Income tax expense was $0.1 million during the three months ended September 30, 2017, compared to income tax expense of $0.5 million during the three months ended September 30, 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 Six Months Ended September 30, 2017 and 2016

Crude Oil Logistics

The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated:



	Six Months Ended September 30,
	2017			2016			Change
	(in thousands, except per barrel amounts)
Revenues:
Crude oil sales	$	890,559		$	756,600		$	133,959
Crude oil transportation and other	56,301			22,106			34,195
Total revenues (1)	946,860			778,706			168,154
Expenses:
Cost of sales	875,563			748,618			126,945
Operating expenses	24,367			18,822			5,545
General and administrative expenses	3,300			2,975			325
Depreciation and amortization expense	41,793			17,993			23,800
(Gain) loss on disposal or impairment of assets, net	(3,716		)	9,962			(13,678		)
Total expenses	941,307			798,370			142,937
Segment operating income (loss)	$	5,553		$	(19,664	)	$	25,217

Crude oil sold (barrels)	18,582			17,311			1,271
Crude oil transported on owned pipelines (barrels)	14,948			—			14,948
Crude oil storage capacity - owned and leased (barrels) (2)	6,159			6,355			(196		)
Crude oil storage capacity sub-leased to third parties (barrels) (2)	700			2,000			(1,300		)
Crude oil inventory (barrels) (2)	1,682			1,982			(300		)
Crude oil sold ($/barrel)	$	47.926		$	43.706		$	4.220
Cost per crude oil sold ($/barrel)	$	47.119		$	43.245		$	3.874
Crude oil product margin ($/barrel)	$	0.807		$	0.461		$	0.346


(1)	Revenues include $4.9 million and $2.9 million of intersegment sales during the six months ended September 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of September 30, 2017 and September 30, 2016, respectively.

Crude Oil Sales. The increase was due primarily to an increase in crude oil prices and barrels sold during the six months ended September 30, 2017, compared to the six months ended September 30, 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 this lower price environment to support our various pipeline, terminal and transportation assets.

Crude Oil Transportation and Other Revenues. The increase was due primarily to our Grand Mesa Pipeline becoming operational on November 1, 2016 with revenues of $38.4 million and higher revenues in our trucking operations during the six months ended September 30, 2017, due to an increase in demand for transportation services, compared to the six months ended September 30, 2016, 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 six months ended September 30, 2017, compared to the six months ended September 30, 2016.

Cost of Sales. The increase was due primarily to an increase in crude oil prices during the six months ended September 30, 2017, compared to the six months ended September 30, 2016. Our cost of sales during the six months ended September 30, 2017 was reduced by $4.2 million of net realized gains on derivatives and increased by $1.5 million of net unrealized losses on derivatives. Our cost of sales during the six months ended September 30, 2016 was increased by $5.5 million of net realized losses on derivatives and $0.2 million of net unrealized losses on derivatives.

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Operating and General and Administrative Expenses. The increase was due primarily to our Grand Mesa Pipeline project becoming operational on November 1, 2016. During the six months ended September 30, 2017, we incurred expenses of $6.9 million related to Grand Mesa. This increase was partially offset by lower repair and maintenance expense related to having a newer fleet of barges and the timing of repairs, lower repair and maintenance expense and lower insurance expense related to having a smaller fleet of trucks, and lower property taxes due to decreased inventory.

Depreciation and Amortization Expense. The increase was due primarily to our Grand Mesa Pipeline project becoming operational on November 1, 2016. During the six months ended September 30, 2017, we incurred depreciation and amortization expense of $21.1 million related to Grand Mesa. 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 six months ended September 30, 2017, we recorded a net gain of $3.7 million on the sales of excess pipe and certain other assets. During the six months ended September 30, 2016, we recorded a net loss of $6.3 million on the sales of certain assets and a loss of $3.7 million due to the write-down of certain other assets.

Water Solutions

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



	Six Months Ended September 30,
	2017			2016			Change
	(in thousands, except per barrel and per day amounts)
Revenues:
Service fees	$	68,603		$	54,225		$	14,378
Recovered hydrocarbons	20,406			12,877			7,529
Other revenues	8,990			8,384			606
Total revenues	97,999			75,486			22,513
Expenses:
Cost of sales-derivative loss	2,048			2,687			(639		)
Cost of sales-other	779			707			72
Operating expenses	47,529			40,505			7,024
General and administrative expenses	1,299			1,271			28
Depreciation and amortization expense	49,261			49,563			(302		)
Loss (gain) on disposal or impairment of assets, net	185			(94,281		)	94,466
Revaluation of liabilities	5,600			—			5,600
Total expenses	106,701			452			106,249
Segment operating (loss) income	$	(8,702	)	$	75,034		$	(83,736	)

Wastewater processed (barrels per day)
Eagle Ford Basin	215,156			209,936			5,220
Permian Basin	252,810			168,927			83,883
DJ Basin	110,685			59,950			50,735
Other Basins	61,223			38,913			22,310
Total	639,874			477,726			162,148
Solids processed (barrels per day)	4,986			2,652			2,334
Skim oil sold (barrels per day)	2,572			1,773			799
Service fees for wastewater processed ($/barrel)	$	0.59		$	0.62		$	(0.03	)
Recovered hydrocarbons for wastewater processed ($/barrel)	$	0.17		$	0.15		$	0.02
Operating expenses for wastewater processed ($/barrel)	$	0.41		$	0.46		$	(0.05	)

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

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) and lower revenues from trucking wastewater to our water solutions facilities in one basin due to a new water pipeline being placed into service during the six months ended September 30, 2017.

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 six months ended September 30, 2017 included $1.0 million of net realized gains on derivatives and $3.0 million of net unrealized losses on derivatives. Our cost of sales during the six months ended September 30, 2016 included $3.5 million of net realized losses on derivatives and $0.8 million of net unrealized gains on derivatives.

Cost of Sales-Other. The increase was due primarily to an increase in expenses for newly offered trucking services to bring wastewater to our water solutions facilities in one basin, partially offset by lower trucking expenses to bring wastewater to our water solutions facilities in another basin due to a new water pipeline being placed into service during the six months ended September 30, 2017.

Depreciation and Amortization Expense. The decrease was due primarily to lower amortization expense from the write-off of an intangible asset during the six months ended September 30, 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 six months ended September 30, 2017, we recorded a net loss of $1.5 million on the sales 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 six months ended September 30, 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;


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


•	a loss of $0.8 million on the sales of certain assets.

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 six months ended September 30, 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:



	Six Months Ended September 30,
	2017			2016		Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	330,448		$	198,084	$	132,364
Cost of sales	314,274			187,826		126,448
Product margin	16,174			10,258		5,916

Butane sales:
Revenues (1)	179,777			121,255		58,522
Cost of sales	191,247			112,836		78,411
Product (loss) margin	(11,470		)	8,419		(19,889		)

Other product sales:
Revenues (1)	186,712			128,180		58,532
Cost of sales	177,540			117,386		60,154
Product margin	9,172			10,794		(1,622		)

Other revenues:
Revenues (1)	9,940			15,222		(5,282		)
Cost of sales	1,522			5,659		(4,137		)
Product margin	8,418			9,563		(1,145		)

Expenses:
Operating expenses	16,352			19,540		(3,188		)
General and administrative expenses	2,621			2,244		377
Depreciation and amortization expense	12,471			8,874		3,597
Loss on disposal or impairment of assets, net	117,729			49		117,680
Total expenses	149,173			30,707		118,466
Segment operating (loss) income	$	(126,879	)	$	8,327	$	(135,206	)

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

Propane sold (gallons)	482,508			426,636		55,872
Propane sold ($/gallon)	$	0.685		$	0.464	$	0.221
Cost per propane sold ($/gallon)	$	0.651		$	0.440	$	0.211
Propane product margin ($/gallon)	$	0.034		$	0.024	$	0.010
Propane inventory (gallons) (2)	136,980			146,995		(10,015		)
Propane storage capacity sub-leased to third parties - leased and owned (gallons) (2)	33,495			33,264		231

Butane sold (gallons)	216,936			198,455		18,481
Butane sold ($/gallon)	$	0.829		$	0.611	$	0.218
Cost per butane sold ($/gallon)	$	0.882		$	0.569	$	0.313
Butane product margin ($/gallon)	$	(0.053	)	$	0.042	$	(0.095	)
Butane inventory (gallons) (2)	111,632			72,369		39,263
Butane storage capacity sub-leased to third parties - leased and owned (gallons) (2)	80,346			72,540		7,806

Other products sold (gallons)	192,620			166,477		26,143
Other products sold ($/gallon)	$	0.969		$	0.770	$	0.199
Cost per other products sold ($/gallon)	$	0.922		$	0.705	$	0.217
Other products product margin ($/gallon)	$	0.047		$	0.065	$	(0.018	)
Other products inventory (gallons) (2)	8,810			9,014		(204		)


(1)	Revenues include $35.9 million and $23.4 million of intersegment sales during the six months ended September 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of September 30, 2017 and September 30, 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 $5.5 million of net unrealized gains on derivatives and $0.1 million of net realized gains on derivatives during six months ended September 30, 2017. During the six months ended September 30, 2016, our cost of wholesale propane sales was reduced by $1.0 million of net unrealized gains on derivatives and $0.5 million of net realized gains on derivatives. The increase in cost of sales is due to an increase in commodity prices.

Product margins per gallon of propane sold were higher during the six months ended September 30, 2017 than during the six months ended September 30, 2016. Product margins have improved due to the increase in commodity prices.

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 six months ended September 30, 2017 was increased by $16.5 million of net unrealized losses on derivatives, compared to an increase of $5.3 million of net unrealized losses on derivatives during the six months ended September 30, 2016. Additionally, our cost of butane sales was reduced by $0.8 million of net realized gains on derivatives and $1.0 million of net realized gains on derivatives during the six months ended September 30, 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 six months ended September 30, 2017 than during the six months ended September 30, 2016 due primarily to the unrealized losses on derivatives noted above. The butane product margins, excluding the unrealized losses on derivatives, were $0.023 per gallon for the six months ended September 30, 2017.

Our cost of sales of other products was increased by $0.3 million of net unrealized losses on derivatives and reduced by $0.1 million of net realized gains on derivatives during the six months ended September 30, 2017. Our cost of sales of other products during the six months ended September 30, 2016 was reduced by $0.6 million of net unrealized gains on derivatives and $0.2 million of net realized gains on derivatives.

Product margins during the six months ended September 30, 2017 were reduced due to an increase in unrecovered railcar fleet costs.

Other Revenues. This revenue includes storage, terminaling and transportation services income. Other revenues decreased due to transportation services and increased storage capacity available in the market.

Operating and General and Administrative Expenses. This decrease was due primarily to lower compensation expense, $2.8 million of which resulted from a shift in the recording of compensation expense related to bonuses from the Liquids segment to “Corporate and Other” during the six months ended September 30, 2017. See further discussion within the “Corporate and Other” section below.

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 six months ended September 30, 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 six months ended September 30, 2017, we recorded a net loss of $0.9 million related to the retirement of assets. During the six months ended September 30, 2016, we recorded a net loss of less than $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:



	Six Months Ended September 30,
	2017			2016			Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	96,636		$	77,811		$	18,825
Cost of sales	42,338			28,101			14,237
Product margin	54,298			49,710			4,588

Distillate sales:
Revenues (1)	16,231			16,044			187
Cost of sales	12,405			11,944			461
Product margin	3,826			4,100			(274		)

Other revenues:
Revenues (1)	18,936			17,638			1,298
Cost of sales	6,213			5,466			747
Product margin	12,723			12,172			551

Expenses:
Operating expenses	56,842			52,349			4,493
General and administrative expenses	4,928			4,494			434
Depreciation and amortization expense	23,075			20,392			2,683
Loss (gain) on disposal or impairment of assets, net	1,096			(34		)	1,130
Total expenses	85,941			77,201			8,740
Segment operating loss	$	(15,094	)	$	(11,219	)	$	(3,875	)

Propane sold (gallons)	55,430			49,361			6,069
Propane sold ($/gallon)	$	1.743		$	1.576		$	0.167
Cost per propane sold ($/gallon)	$	0.764		$	0.569		$	0.195
Propane product margin ($/gallon)	$	0.979		$	1.007		$	(0.028	)
Propane inventory (gallons) (2)	11,183			10,625			558

Distillates sold (gallons)	7,707			8,366			(659		)
Distillates sold ($/gallon)	$	2.106		$	1.918		$	0.188
Cost per distillates sold ($/gallon)	$	1.610		$	1.428		$	0.182
Distillates product margin ($/gallon)	$	0.496		$	0.490		$	0.006
Distillates inventory (gallons) (2)	2,793			3,083			(290		)


(1)	Revenues include less than $0.1 million and less than $0.1 million of intersegment sales during the six months ended September 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statement of operations.


(2)	Information is presented as of September 30, 2017 and September 30, 2016, respectively.

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.

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

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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.

Loss (Gain) on Disposal or Impairment of Assets, Net. Amounts represent 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:



	Six Months Ended September 30,
	2017			2016			Change
	(in thousands, except per barrel amounts)
Refined products sales:
Revenues (1)	$	5,647,875		$	4,151,572		$	1,496,303
Cost of sales	5,615,979			4,099,509			1,516,470
Product margin	31,896			52,063			(20,167		)

Renewables sales:
Revenues	213,930			202,312			11,618
Cost of sales	213,720			200,654			13,066
Product margin	210			1,658			(1,448		)

Service fee revenues	168			11,145			(10,977		)

Expenses:
Operating expenses	6,889			16,663			(9,774		)
General and administrative expenses	4,255			5,374			(1,119		)
Depreciation and amortization expense	648			833			(185		)
Gain on disposal or impairment of assets, net	(15,056		)	(119,160		)	104,104
Total income	(3,264		)	(96,290		)	93,026
Segment operating income	$	35,538		$	161,156		$	(125,618	)

Gasoline sold (barrels)	54,975			43,051			11,924
Diesel sold (barrels)	28,788			25,200			3,588
Ethanol sold (barrels)	1,992			2,065			(73		)
Biodiesel sold (barrels)	1,195			1,215			(20		)
Refined products and renewables storage capacity - leased (barrels) (2)	9,070			7,645			1,425
Refined products and renewables storage capacity sub-leased to third parties (barrels) (2)	1,043			1,063			(20		)
Gasoline inventory (barrels) (2)	1,862			1,995			(133		)
Diesel inventory (barrels) (2)	1,148			2,339			(1,191		)
Ethanol inventory (barrels) (2)	513			372			141
Biodiesel inventory (barrels) (2)	375			260			115
Refined products sold ($/barrel)	$	67.427		$	60.828		$	6.599
Cost per refined products sold ($/barrel)	$	67.046		$	60.065		$	6.981
Refined products product margin ($/barrel)	$	0.381		$	0.763		$	(0.382	)
Renewable products sold ($/barrel)	$	67.126		$	61.680		$	5.446
Cost per renewable products sold ($/barrel)	$	67.060		$	61.175		$	5.885
Renewable products product margin ($/barrel)	$	0.066		$	0.505		$	(0.439	)


(1)	Revenues include $0.1 million and $0.1 million of intersegment sales during the six months ended September 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.


(2)	Information is presented as of September 30, 2017 and September 30, 2016, respectively.

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purchased during the fiscal year ended March 31, 2017, an expansion of our refined products operations and the continued demand for motor fuels. The decrease in margin was due primarily to the negative impact of the continued decline in gasoline line space values on the Colonial Pipeline, discretionary terminal volume profitability and line space sales during the six months ended September 30, 2017.

Renewables Revenues and Cost of Sales. The increases in revenues and cost of sales were due primarily to increase in renewables sale prices, partially offset by decreased volumes. The decreased volumes were due primarily to lower margins in current market conditions.

Service Fee Revenues, Operating Expenses, General and Administrative Expenses. The decrease was 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 six months ended September 30, 2017, we recorded $15.1 million of the deferred gain from the sale of the general partner in 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 six months ended September 30, 2016, we recorded:


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


•	$15.1 million of the deferred gain from the sale of the general partner in 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); and


•	a gain of less than $0.1 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:



	Six Months Ended September 30,
	2017			2016			Change
	(in thousands)
Other revenues	$	407		$	515		$	(108	)

Expenses:
Cost of sales	194			223			(29		)
Operating expenses	491			564			(73		)
General and administrative expenses	32,068			53,439			(21,371		)
Depreciation and amortization expense	1,839			1,854			(15		)
Gain on disposal or impairment of assets, net	—			(3		)	3
Total expenses	34,592			56,077			(21,485		)
Operating loss	$	(34,185	)	$	(55,562	)	$	21,377

General and Administrative Expenses. The expense associated with the service award units was $8.6 million during the six months ended September 30, 2017, compared to $27.7 million during the six months ended September 30, 2016. During the six months ended September 30, 2017, due to the cancellation of awards in the prior year which caused an acceleration of expense as well as vested units in July were not offset by grants as in the prior year. In addition, during the first quarter of our prior fiscal year the expense for the service awards being 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. The decrease from the prior year was partially offset by $2.8 million of compensation expense that was shifted from our Liquids segment during the three months ended September 30, 2017 due to our expectation of paying these amounts in common units.

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Equity in Earnings of Unconsolidated Entities

The increase of $3.4 million during the six months ended September 30, 2017 was due primarily to increased earnings related to our investments in Glass Mountain and E Energy Adams, LLC.

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 $35.6 million during the six months ended September 30, 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 six months ended September 30, 2017, compared to $1.9 billion during the six months ended September 30, 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:



	Six Months Ended September 30,
	2017			2016
	(in thousands)
Early extinguishment of long-term debt (1)	$	(1,338	)	$	8,614
Release of contingent consideration liabilities (2)	—			22,276
(Loss) gain on early extinguishment of liabilities, net	$	(1,338	)	$	30,890

(1)

During the six months ended September 30, 2017, this relates to net losses on the early extinguishment of a portion of the senior secured notes, the 2019 Notes, the 2023 Notes and the 2025 Notes. During the six months ended September 30, 2016, this relates to gains on the early extinguishment of a portion of the 2019 Notes and the 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 three months ended September 30, 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:



	Six Months Ended September 30,
	2017			2016
	(in thousands)
Interest income (1)	$	3,958		$	4,420
Crude oil marketing arrangement (2)	(10		)	(1,551		)
Other (3)	58			2,984
Other income, net	$	4,006		$	5,853

(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 six months ended September 30, 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.

Income Tax Expense

Income tax expense was $0.6 million during the six months ended September 30, 2017, compared to income tax expense of $0.9 million during the six months ended September 30, 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 $6.3 million during the six months ended September 30, 2017 was due primarily to adjustments related to noncontrolling interests during the six months ended September 30, 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 (loss) income, (loss) income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information 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.

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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 (loss) income to EBITDA and Adjusted EBITDA:



	Three Months Ended September 30,						Six Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Net (loss) income	$	(173,579	)	$	(66,658	)	$	(237,286	)	$	116,095
Less: Net (income) loss attributable to noncontrolling interests	(80		)	59			(132		)	(5,774		)
Less: Net loss attributable to redeemable noncontrolling interests	288			—			685			—
Net (loss) income attributable to NGL Energy Partners LP	(173,371		)	(66,599		)	(236,733		)	110,321
Interest expense	50,288			33,489			99,566			63,797
Income tax expense	111			460			570			922
Depreciation and amortization	69,426			54,522			137,489			107,102
EBITDA	(53,546		)	21,872			892			282,142
Net unrealized losses on derivatives	18,077			2,293			16,076			3,220
Inventory valuation adjustment (1)	(2,165		)	39,530			(21,347		)	32,693
Lower of cost or market adjustments	5,333			(393		)	9,411			108
Loss (gain) on disposal or impairment of assets, net	111,451			851			100,238			(203,504		)
(Gain) loss on early extinguishment of liabilities, net	(1,943		)	(938		)	1,338			(30,890		)
Revaluation of investments	—			—			—			14,365
Equity-based compensation expense (2)	6,065			10,660			14,886			32,994
Acquisition expense (3)	264			724			(54		)	1,161
Revaluation of liabilities	5,600			—			5,600			—
Other (4)	1,616			889			2,641			7,117
Adjusted EBITDA	$	90,752		$	75,488		$	129,681		$	139,406


(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 for the three months ended September 30, 2017 and 2016 and the six months ended September 30, 2016 represent expenses we incurred related to legal and advisory costs associated with acquisitions. The amount for the six months ended September 30, 2017 represents reimbursement for certain legal costs incurred in prior periods, partially offset by expenses we incurred related to legal and advisory costs associated with acquisitions.

(4)

Amounts for the three months ended September 30, 2017 and 2016 and the six months ended September 30, 2017 represent non-cash operating expenses related to our Grand Mesa Pipeline and accretion expense for asset retirement obligations. The amount for the six months ended September 30, 2016 represents non-cash operating expenses related to our Grand Mesa Pipeline, adjustments related to noncontrolling interests and accretion expense for asset retirement obligations.

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



	Three Months Ended September 30,						Six Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Reconciliation to unaudited condensed consolidated statements of operations:
Depreciation and amortization per EBITDA table	$	69,426		$	54,522		$	137,489		$	107,102
Intangible asset amortization recorded to cost of sales	(1,506		)	(1,749		)	(3,091		)	(3,345		)
Depreciation and amortization of unconsolidated entities	(3,029		)	(2,999		)	(6,028		)	(6,068		)
Depreciation and amortization attributable to noncontrolling interests	317			829			717			1,820
Depreciation and amortization per unaudited condensed consolidated statements of operations	$	65,208		$	50,603		$	129,087		$	99,509



	Six Months Ended September 30,
	2017			2016
	(in thousands)
Reconciliation to unaudited condensed consolidated statements of cash flows:
Depreciation and amortization per EBITDA table	$	137,489		$	107,102
Amortization of debt issuance costs recorded to interest expense	5,509			5,279
Depreciation and amortization of unconsolidated entities	(6,028		)	(6,068		)
Depreciation and amortization attributable to noncontrolling interests	717			1,820
Depreciation and amortization per unaudited condensed consolidated statements of cash flows	$	137,687		$	108,133

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 September 30,						Six Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Interest expense per EBITDA table	$	50,288		$	33,489		$	99,566		$	63,797
Interest expense attributable to noncontrolling interests	9			4			18			8
Interest expense attributable to unconsolidated entities	(64		)	(51		)	(125		)	75
Interest expense per unaudited condensed consolidated statements of operations	$	50,233		$	33,442		$	99,459		$	63,880

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



	Three Months Ended September 30, 2017
	Crude Oil Logistics			Water Solutions			Liquids			Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating income (loss)	$	1,196		$	(7,548	)	$	(118,107	)	$	(9,226	)	$	21,042		$	(16,459	)	$	(129,102	)
Depreciation and amortization	20,958			25,253			6,141			11,613			324			919			65,208
Amortization recorded to cost of sales	84			—			71			—			1,351			—			1,506
Net unrealized losses on derivatives	2,170			3,022			12,682			203			—			—			18,077
Inventory valuation adjustment	—			—			—			—			(2,165		)	—			(2,165		)
Lower of cost or market adjustments	—			—			(2,476		)	—			7,809			—			5,333
(Gain) loss on disposal or impairment of assets, net	(157		)	915			117,729			493			(7,528		)	—			111,452
Equity-based compensation expense	—			—			—			—			—			6,065			6,065
Acquisition expense	—			—			—			—			—			264			264
Other income, net	50			2			3			69			167			1,605			1,896
Adjusted EBITDA attributable to unconsolidated entities	3,798			127			—			(19		)	1,216			—			5,122
Adjusted EBITDA attributable to noncontrolling interest	—			(190		)	—			70			—			—			(120		)
Revaluation of liabilities	—			5,600			—			—			—			—			5,600
Other	1,502			92			22			—			—			—			1,616
Adjusted EBITDA	$	29,601		$	27,273		$	16,065		$	3,203		$	22,216		$	(7,606	)	$	90,752



	Three Months Ended September 30, 2016
	Crude Oil Logistics			Water Solutions			Liquids		Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating (loss) income	$	(19,039	)	$	(4,430	)	$	8,384	$	(8,717	)	$	11,387		$	(23,413	)	$	(35,828	)
Depreciation and amortization	9,025			25,129			4,425		10,705			416			903			50,603
Amortization recorded to cost of sales	100			—			195		—			1,454			—			1,749
Net unrealized losses (gains) on derivatives	1,613			(2,193		)	2,734		139			—			—			2,293
Inventory valuation adjustment	—			—			—		—			39,530			—			39,530
Lower of cost or market adjustments	—			—			—		—			(393		)	—			(393		)
Loss (gain) on disposal or impairment of assets, net	8,477			(11		)	17		(65		)	(7,563		)	(3		)	852
Equity-based compensation expense	—			—			—		—			—			10,660			10,660
Acquisition expense	—			—			—		—			—			724			724
Other income, net	145			—			24		139			11			1,762			2,081
Adjusted EBITDA attributable to unconsolidated entities	2,386			46			—		(111		)	782			—			3,103
Adjusted EBITDA attributable to noncontrolling interest	—			(794		)	—		19			—			—			(775		)
Other	793			76			20		—			—			—			889
Adjusted EBITDA	$	3,500		$	17,823		$	15,799	$	2,109		$	45,624		$	(9,367	)	$	75,488

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	Six Months Ended September 30, 2017
	Crude Oil Logistics			Water Solutions			Liquids			Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating income (loss)	$	5,553		$	(8,702	)	$	(126,879	)	$	(15,094	)	$	35,538		$	(34,185	)	$	(143,769	)
Depreciation and amortization	41,793			49,261			12,471			23,075			648			1,839			129,087
Amortization recorded to cost of sales	169			—			141			—			2,781			—			3,091
Net unrealized losses on derivatives	1,511			3,022			11,313			230			—			—			16,076
Inventory valuation adjustment	—			—			—			—			(21,347		)	—			(21,347		)
Lower of cost or market adjustments	—			—			—			—			9,411			—			9,411
(Gain) loss on disposal or impairment of assets, net	(3,716		)	185			117,729			1,096			(15,056		)	—			100,238
Equity-based compensation expense	—			—			—			—			—			14,886			14,886
Acquisition expense	—			—			—			—			—			(54		)	(54		)
Other income, net	94			20			7			251			335			3,299			4,006
Adjusted EBITDA attributable to unconsolidated entities	7,620			281			—			(11		)	2,107			—			9,997
Adjusted EBITDA attributable to noncontrolling interest	—			(434		)	—			252			—			—			(182		)
Revaluation of liabilities	—			5,600			—			—			—			—			5,600
Other	2,413			185			43			—			—			—			2,641
Adjusted EBITDA	$	55,437		$	49,418		$	14,825		$	9,799		$	14,417		$	(14,215	)	$	129,681



	Six Months Ended September 30, 2016
	Crude Oil Logistics			Water Solutions			Liquids		Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating (loss) income	$	(19,664	)	$	75,034		$	8,327	$	(11,219	)	$	161,156		$	(55,562	)	$	158,072
Depreciation and amortization	17,993			49,563			8,874		20,392			833			1,854			99,509
Amortization recorded to cost of sales	184			—			390		—			2,771			—			3,345
Net unrealized losses (gains) on derivatives	219			(834		)	3,626		209			—			—			3,220
Inventory valuation adjustment	—			—			—		—			32,693			—			32,693
Lower of cost or market adjustments	—			—			—		—			108			—			108
Loss (gain) on disposal or impairment of assets, net	9,962			(94,281		)	49		(34		)	(119,160		)	(3		)	(203,467		)
Equity-based compensation expense	—			—			—		—			—			32,994			32,994
Acquisition expense	—			—			—		2			—			1,159			1,161
Other (expense) income, net	(1,310		)	310			63		320			2,879			3,591			5,853
Adjusted EBITDA attributable to unconsolidated entities	5,074			(63		)	—		(277		)	1,676			—			6,410
Adjusted EBITDA attributable to noncontrolling interest	—			(1,631		)	—		141			—			—			(1,490		)
Other	795			163			40		—			—			—			998
Adjusted EBITDA	$	13,253		$	28,261		$	21,369	$	9,534		$	82,956		$	(15,967	)	$	139,406

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, including the Glass Mountain pipeline extension, among others. We expect to be able to finance these projects through available capacity on our Revolving Credit Facility (as defined herein), asset sales or other forms of financing.

Other sources of liquidity during the six months ended September 30, 2017 are discussed below.

Class B Preferred Units

Long-Term Debt

Credit Agreement

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 September 30, 2017, we were in compliance with the covenants under the Credit Agreement.

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Senior Secured Notes

During the six months ended September 30, 2017, we repurchased $55.0 million of our senior secured notes for an aggregate purchase price of $57.2 million (excluding payments of accrued interest), and recorded a loss on the early extinguishment of $3.2 million (net of $1.0 million of debt issuance costs). Following the repurchase, semi-annual installment payments will be $19.5 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022.

At September 30, 2017, we were in compliance with the covenants under the note purchase agreement for our senior secured notes.

Senior Unsecured Notes

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

Repurchases

During the six months ended September 30, 2017, we repurchased $18.7 million of the 2019 Notes, $26.5 million of the 2023 Notes, and $15.7 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 September 30, 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)
Six Months Ended September 30, 2017
Expansion capital borrowings	$	97,123	$	—	$	193,500
Working capital borrowings	$	783,653	$	719,500	$	869,500

Six Months Ended September 30, 2016
Expansion capital borrowings	$	1,258,478	$	1,153,500	$	1,338,000
Working capital borrowings	$	629,292	$	465,500	$	718,000

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 six months ended September 30, 2017, and approximately $134.7 million remained available for sale under the ATM Program as of September 30, 2017.

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Common Unit Repurchase Program

Capital Expenditures

The following table summarizes expansion and maintenance capital expenditures for the periods indicated which excludes additions for tank bottoms and line fill. This information has been prepared on the accrual basis, and excludes property, plant and equipment and intangible assets acquired in acquisitions.



	Capital Expenditures
	Expansion		Maintenance		Total
	(in thousands)
Three Months Ended September 30,
2017	$	19,439	$	7,994	$	27,433
2016	$	48,781	$	6,401	$	55,182

Six Months Ended September 30,
2017	$	44,032	$	14,521	$	58,553
2016	$	143,884	$	12,696	$	156,580

During the three months and six months ended September 30, 2017, we spent $28.5 million and $48.4 million, respectively, compared to $98.8 million and $113.3 million, respectively, during the three months and six months ended September 30, 2016. See Note 4 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion of the acquisitions made during our current fiscal year. In addition, we contributed $8.9 million and $14.2 million, respectively, during the three months and six months ended September 30, 2017, for the construction of the Glass Mountain pipeline extension.

Cash Flows

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



	Six Months Ended September 30,
Cash Flows Provided by (Used in)	2017			2016
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	65,847		$	78,731
Changes in operating assets and liabilities	(55,893		)	(133,608		)
Operating activities	$	9,954		$	(54,877	)
Investing activities	$	(108,212	)	$	(235,542	)
Financing activities	$	104,401		$	285,670

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

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operating activities during the six months ended September 30, 2017 was due primarily to higher inventory as a result of the purchase of additional pipeline capacity allocations in our Refined Products and Renewables segment during the six months ended September 30, 2016.

Investing Activities. Net cash used in investing activities was $108.2 million during the six months ended September 30, 2017, compared to $235.5 million during the six months ended September 30, 2016. The decrease in net cash used in investing activities was due primarily to:


•	a decrease in capital expenditures from $201.6 million during the six months ended September 30, 2016, primarily related to the Grand Mesa Pipeline, to $56.5 million during the six months ended September 30, 2017;


•	a $64.9 million decrease in cash paid for acquisitions during the six months ended September 30, 2017;


•	a $24.2 million increase in proceeds primarily from the sale of excess pipe in our Crude Oil Logistics segment during the six months ended September 30, 2017; and


•	a $16.9 million payment to terminate a development agreement during the six months ended September 30, 2016.

These decreases in net cash used in investing activities were partially offset by:


•	$112.4 million in proceeds received from the sale of the TLP common units we owned during the six months ended September 30, 2016; and


•	$14.2 million of investments in unconsolidated entities during the six months ended September 30, 2017.

Financing Activities. Net cash provided by financing activities was $104.4 million during the six months ended September 30, 2017, compared to $285.7 million during the six months ended September 30, 2016. The decrease in net cash provided by financing activities was due primarily to:


•	an increase of $100.3 million in repurchases of a portion of our outstanding senior secured notes and senior unsecured notes during the six months ended September 30, 2017;


•	a decrease of $32.3 million in proceeds received from the sale of preferred units;


•	an increase of $24.0 million in distributions paid to our general and common unit partners, preferred unitholders and noncontrolling interest owners during the six months ended September 30, 2017;


•	a decrease of $17.5 million in borrowings on our Revolving Credit Facility (net of repayments) during the six months ended September 30, 2017;


•	$11.7 million for the repurchase of a portion of our common units during the six months ended September 30, 2017; and


•	$10.5 million for the repurchase of warrants related to our Class A Preferred Units during the six months ended September 30, 2017.

These decreases in net cash provided by financing activities were partially offset by a $25.8 million release of contingent consideration liabilities related to the termination of a development agreement during the six months ended September 30, 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 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, which was paid to the holders of the Class B Preferred Units on October 16, 2017.

On October 19, 2017, the board of directors of our general partner declared a distribution of $0.39 per common unit to the unitholders of record on November 6, 2017. In addition, the board of directors declared a distribution to the holders of the

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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 November 14, 2017.

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 September 30, 2017 for our fiscal years ending thereafter:



			Six 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	$	102,000	$	—	$	—	$	—	$	—	$	102,000	$	—
Working capital borrowings	869,500		—		—		—		—		869,500		—
Senior secured notes	195,000		19,500		39,000		39,000		39,000		39,000		19,500
Senior unsecured notes	1,885,672		—		—		360,781		—		367,048		1,157,843
Other long-term debt	12,756		1,793		2,895		2,285		5,450		274		59
Interest payments on long-term debt:
Revolving Credit Facility (1)	214,743		38,001		49,095		49,095		49,095		29,457		—
Senior secured notes	34,178		7,918		10,374		7,781		5,187		2,594		324
Senior unsecured notes	701,364		61,952		123,904		114,659		105,414		105,414		190,021
Other long-term debt	1,581		336		525		369		185		43		123
Letters of credit	115,099		—		—		—		—		115,099		—
Future minimum lease payments under noncancelable operating leases	553,578		71,787		120,589		107,255		94,118		65,985		93,844
Future minimum throughput payments under noncancelable agreements (2)	120,394		26,001		52,042		42,351		—		—		—
Construction commitments (3)	24,470		24,026		444		—		—		—		—
Fixed-price commodity purchase commitments:
Crude oil	161,432		161,432		—		—		—		—		—
Natural gas liquids	46,156		44,816		1,340		—		—		—		—
Index-price commodity purchase commitments (4):
Crude oil (5)	1,770,080		576,009		524,256		412,569		161,485		95,761		—
Natural gas liquids	601,243		563,817		37,426		—		—		—		—
Total contractual obligations	$	7,409,246	$	1,597,388	$	961,890	$	1,136,145	$	459,934	$	1,792,175	$	1,461,714


(1)	The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at September 30, 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 September 30, 2017, construction commitments primarily relate to the Glass Mountain pipeline extension.

(4)

Index prices are based on a forward price curve at September 30, 2017. A theoretical change of $0.10 per gallon of natural gas liquids in the underlying commodity price at September 30, 2017 would result in a change of $67.0 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 September 30, 2017 would result in a change of $39.1 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 September 30, 2017, we had $971.5 million of outstanding borrowings under our Revolving Credit Facility at a weighted average interest rate of 4.50%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.2 million, based on borrowings outstanding at September 30, 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 September 30, 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 September 30, 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)	$	(5,451	)
Propane (Liquids segment)	$	1,404
Other products (Liquids segment)	$	(14,458	)
Gasoline (Refined Products and Renewables segment)	$	(15,196	)
Diesel (Refined Products and Renewables segment)	$	(4,990	)
Ethanol (Refined Products and Renewables segment)	$	(2,753	)
Biodiesel (Refined Products and Renewables segment)	$	124
Canadian dollars (Liquids segment)	$	711

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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 September 30, 2017. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of September 30, 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 September 30, 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 September 30, 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
July 1-31, 2017	37,554	$	13.58	—	$	—
August 1-31, 2017	227,192	$	9.00	227,192	$	12,948,047
September 1-30, 2017	966,443	$	9.39	966,443	$	3,847,062
Total	1,231,189			1,193,635	$	3,847,062

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

None.

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Item 6. Exhibits



Exhibit Number		Exhibit
4.1		Amendment No. 2 to Amended and Restated Note Purchase Agreement, dated August 2, 2017 and effective as of June 2, 2017, among NGL Energy Partners LP and the purchasers named therein (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) filed with the SEC on August 4, 2017)
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 September 30, 2017 and March 31, 2017, (ii) Unaudited Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2017 and 2016, (iii) Unaudited Condensed Consolidated Statements of Comprehensive (Loss) Income for the three months and six months ended September 30, 2017 and 2016, (iv) Unaudited Condensed Consolidated Statement of Changes in Equity for the six months ended September 30, 2017, (v) Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 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: November 7, 2017		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer

Date: November 7, 2017		By:	/s/ Robert W. Karlovich III
			Robert W. Karlovich III
			Chief Financial Officer