Edgar Filing: NGL Energy Partners LP

Document

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended December 31, 2016

¨ 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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer x		Accelerated filer ¨

Non-accelerated filer ¨ (Do not check if a smaller reporting company)		Smaller reporting company ¨

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

At February 6, 2017, there were 110,059,407 common units issued and outstanding.

Table of Contents

TABLE OF CONTENTS



PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements	3
	Unaudited Condensed Consolidated Balance Sheets at December 31, 2016 and March 31, 2016	3
	Unaudited Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2016 and 2015	4
	Unaudited Condensed Consolidated Statements of Comprehensive Income for the three months and nine months ended December 31, 2016 and 2015	5
	Unaudited Condensed Consolidated Statement of Changes in Equity for the nine months ended December 31, 2016	6
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2016 and 2015	7
	Notes to Unaudited Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	84
Item 4.	Controls and Procedures	85
PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	86
Item 1A.	Risk Factors	86
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	86
Item 3.	Defaults Upon Senior Securities	86
Item 4.	Mine Safety Disclosures	86
Item 5.	Other Information	86
Item 6.	Exhibits	87
SIGNATURES		88
INDEX TO EXHIBITS		89

Table of Contents

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, refined products, ethanol, and biodiesel;


•	energy prices generally;


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


•	the general level of demand for crude oil, natural gas liquids, refined products, ethanol, and biodiesel;


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


•	the level of crude oil and natural gas drilling and production in producing 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, refined products, 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, water disposal, recycling, and discharge services;


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

Table of Contents


•	the nonpayment or nonperformance by our counterparties;


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


•	a deterioration of the credit and capital markets;


•	the ability to successfully identify and consummate strategic acquisitions, 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, 2016 and under Part II, Item 1A–“Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2016.

Table of Contents

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Balance Sheets

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



	December 31, 2016			March 31, 2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	28,927		$	28,176
Accounts receivable-trade, net of allowance for doubtful accounts of $5,578 and $6,928, respectively	765,290			521,014
Accounts receivable-affiliates	20,008			15,625
Inventories	613,993			367,806
Prepaid expenses and other current assets	134,485			95,859
Total current assets	1,562,703			1,028,480
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $348,136 and $266,491, respectively	1,746,925			1,649,572
GOODWILL	1,462,116			1,315,362
INTANGIBLE ASSETS, net of accumulated amortization of $388,517 and $316,878, respectively	1,164,749			1,148,890
INVESTMENTS IN UNCONSOLIDATED ENTITIES	187,514			219,550
LOAN RECEIVABLE-AFFILIATE	2,700			22,262
OTHER NONCURRENT ASSETS	251,369			176,039
Total assets	$	6,378,076		$	5,560,155
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	650,886		$	420,306
Accounts payable-affiliates	22,917			7,193
Accrued expenses and other payables	196,033			214,426
Advance payments received from customers	63,509			56,185
Current maturities of long-term debt	33,501			7,907
Total current liabilities	966,846			706,017
LONG-TERM DEBT, net of debt issuance costs of $24,574 and $15,500, respectively, and current maturities	3,216,505			2,912,837
OTHER NONCURRENT LIABILITIES	186,280			247,236
COMMITMENTS AND CONTINGENCIES (NOTE 10)

CLASS A 10.75% CONVERTIBLE PREFERRED UNITS, 19,942,169 and 0 preferred units issued and outstanding, respectively	61,170			—

EQUITY:
General partner, representing a 0.1% interest, 109,201 and 104,274 notional units, respectively	(50,785		)	(50,811		)
Limited partners, representing a 99.9% interest, 109,091,710 and 104,169,573 common units issued and outstanding, respectively	1,969,113			1,707,326
Accumulated other comprehensive loss	(97		)	(157		)
Noncontrolling interests	29,044			37,707
Total equity	1,947,275			1,694,065
Total liabilities and equity	$	6,378,076		$	5,560,155

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Operations

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



				As Restated						As Restated
	Three Months Ended December 31,						Nine Months Ended December 31,
	2016			2015			2016			2015
REVENUES:
Crude Oil Logistics	$	385,906		$	519,425		$	1,161,742		$	2,854,787
Water Solutions	40,359			45,438			115,845			147,225
Liquids	470,275			353,527			909,584			861,504
Retail Propane	128,654			100,145			240,131			217,798
Refined Products and Renewables	2,381,283			1,666,471			6,746,168			5,335,356
Other	164			—			679			—
Total Revenues	3,406,641			2,685,006			9,174,149			9,416,670
COST OF SALES:
Crude Oil Logistics	361,839			495,529			1,107,587			2,770,240
Water Solutions	477			(3,128		)	3,871			(8,088		)
Liquids	430,946			300,766			831,221			754,157
Retail Propane	60,508			45,974			106,019			96,417
Refined Products and Renewables	2,374,175			1,594,359			6,674,194			5,149,151
Other	77			—			300			—
Total Cost of Sales	3,228,022			2,433,500			8,723,192			8,761,877
OPERATING COSTS AND EXPENSES:
Operating	76,981			104,721			225,408			307,941
General and administrative	18,280			23,035			88,077			114,814
Depreciation and amortization	60,767			59,180			160,276			175,772
Loss (gain) on disposal or impairment of assets, net	34			1,328			(203,433		)	3,040
Revaluation of liabilities	—			(19,312		)	—			(46,416		)
Operating Income	22,557			82,554			180,629			99,642
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	1,279			2,858			1,726			14,008
Revaluation of investments	—			—			(14,365		)	—
Interest expense	(41,436		)	(36,176		)	(105,316		)	(98,549		)
Gain on early extinguishment of liabilities	—			—			30,890			—
Other income, net	20,007			2,161			25,860			2,941
Income Before Income Taxes	2,407			51,397			119,424			18,042
INCOME TAX (EXPENSE) BENEFIT	(1,114		)	(402		)	(2,036		)	1,846
Net Income	1,293			50,995			117,388			19,888
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(317		)	(6,838		)	(6,091		)	(14,685		)
NET INCOME ATTRIBUTABLE TO NGL ENERGY PARTNERS LP	976			44,157			111,297			5,203
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS	(8,906		)	—			(20,958		)	—
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER	(22		)	(16,239		)	(180		)	(47,798		)
NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS	$	(7,952	)	$	27,918		$	90,159		$	(42,595	)
BASIC (LOSS) INCOME PER COMMON UNIT	$	(0.07	)	$	0.27		$	0.85		$	(0.41	)
DILUTED (LOSS) INCOME PER COMMON UNIT	$	(0.07	)	$	0.22		$	0.82		$	(0.41	)
BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	107,966,901			105,338,200			106,114,668			104,808,649
DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	107,966,901			106,194,547			109,554,928			104,808,649

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Comprehensive Income

(U.S. Dollars in Thousands)



			As Restated					As Restated
	Three Months Ended December 31,					Nine Months Ended December 31,
	2016		2015			2016		2015
Net income	$	1,293	$	50,995		$	117,388	$	19,888
Other comprehensive income (loss)	545		(12		)	60		(39		)
Comprehensive income	$	1,838	$	50,983		$	117,448	$	19,849

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statement of Changes in Equity

Nine Months Ended December 31, 2016

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



				Limited Partners				Accumulated Other
	General Partner			Common Units	Amount			Comprehensive (Loss) Income			Noncontrolling Interests			Total Equity
BALANCES AT MARCH 31, 2016	$	(50,811	)	104,169,573	$	1,707,326		$	(157	)	$	37,707		$	1,694,065
Distributions to partners	(213		)	—	(131,922		)	—			—			(132,135		)
Distributions to noncontrolling interest owners	—			—	—			—			(3,292		)	(3,292		)
Contributions	59			—	(501		)	—			1,140			698
Business combinations				218,617	3,947			—			—			3,947
Purchase of noncontrolling interest (Notes 4 and 15)	—			—	(215		)	—			(12,602		)	(12,817		)
Equity issued pursuant to incentive compensation plan	—			2,350,082	61,646			—			—			61,646
Common units issued, net of offering costs	—			2,353,438	43,896			—			—			43,896
Allocation of value to beneficial conversion feature of Class A convertible preferred units	—			—	131,534			—			—			131,534
Issuance of warrants	—			—	48,550			—			—			48,550
Accretion of beneficial conversion feature of Class A convertible preferred units	—			—	(6,265		)	—			—			(6,265		)
Net income	180			—	111,117			—			6,091			117,388
Other comprehensive income	—			—	—			60			—			60
BALANCES AT DECEMBER 31, 2016	$	(50,785	)	109,091,710	$	1,969,113		$	(97	)	$	29,044		$	1,947,275

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Cash Flows

(U.S. Dollars in Thousands)



				As Restated
	Nine Months Ended December 31,
	2016			2015
OPERATING ACTIVITIES:
Net income	$	117,388		$	19,888
Adjustments to reconcile net income to net cash (used in) provided by operating activities:
Depreciation and amortization, including amortization of debt issuance costs	173,566			191,081
Gain on early extinguishment or revaluation of liabilities	(30,890		)	(46,416		)
Gain on termination of contract	(16,205		)	—
Non-cash equity-based compensation expense	39,859			50,080
(Gain) loss on disposal or impairment of assets, net	(203,433		)	3,040
Provision for doubtful accounts	471			3,770
Net adjustments to fair value of commodity derivatives	102,638			(97,069		)
Equity in earnings of unconsolidated entities	(1,726		)	(14,008		)
Distributions of earnings from unconsolidated entities	2,094			15,742
Revaluation of investments	14,365			—
Other	(3,269		)	(4,395		)
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable-trade and affiliates	(245,065		)	454,686
Inventories	(244,941		)	29,236
Other current and noncurrent assets	(65,331		)	19,806
Accounts payable-trade and affiliates	245,506			(337,334		)
Other current and noncurrent liabilities	(2,692		)	5,027
Net cash (used in) provided by operating activities	(117,665		)	293,134
INVESTING ACTIVITIES:
Capital expenditures	(264,580		)	(497,147		)
Acquisitions, net of cash acquired	(127,513		)	(187,356		)
Cash flows from settlements of commodity derivatives	(82,815		)	92,216
Proceeds from sales of assets	14,195			4,981
Proceeds from sale of TLP common units	112,370			—
Proceeds from sale of freshwater supply company	22,000			—
Investments in unconsolidated entities	—			(8,373		)
Distributions of capital from unconsolidated entities	7,608			14,043
Loan for natural gas liquids facility	—			(3,913		)
Payments on loan for natural gas liquids facility	6,585			5,552
Loan to affiliate	(2,700		)	(15,621		)
Payments on loan to affiliate	655			517
Payment to terminate development agreement	(16,875		)	—
Net cash used in investing activities	(331,070		)	(595,101		)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	1,176,000			2,042,100
Payments on revolving credit facilities	(1,510,500		)	(1,514,100		)
Issuance of senior notes	700,000			—
Repurchases of senior notes	(15,129		)	—
Proceeds from borrowings under other long-term debt	—			53,223
Payments on other long-term debt	(6,549		)	(3,649		)
Debt issuance costs	(12,608		)	(9,684		)
Contributions from general partner	59			54
Contributions from noncontrolling interest owners, net	639			10,037
Distributions to partners	(132,135		)	(238,414		)
Distributions to noncontrolling interest owners	(3,292		)	(26,638		)
Proceeds from sale of convertible preferred units and warrants, net of offering costs	234,989			—

Table of Contents



Proceeds from sale of common units, net of offering costs	43,896			—
Payments for the early extinguishment of liabilities	(25,884		)	—
Taxes paid on behalf of equity incentive plan participants	—			(19,303		)
Common unit repurchases	—			(7,707		)
Other	—			(76		)
Net cash provided by financing activities	449,486			285,843
Net increase (decrease) in cash and cash equivalents	751			(16,124		)
Cash and cash equivalents, beginning of period	28,176			41,303
Cash and cash equivalents, end of period	$	28,927		$	25,179
Supplemental cash flow information:
Cash interest paid	$	89,102		$	90,217
Income taxes paid (net of income tax refunds)	$	1,985		$	1,778
Supplemental non-cash investing and financing activities:
Value of common units issued in business combinations	$	3,947		$	19,098
Accrued capital expenditures	$	2,754		$	9,139

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

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Note 1—Organization and Operations

NGL Energy Partners LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At December 31, 2016, our operations include:

•


•	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 18 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, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 28 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.

Recent Developments

On February 1, 2016, we completed the sale of our general partner interest in TransMontaigne Partners L.P. (“TLP”) to an affiliate of ArcLight Capital Partners (“ArcLight”). As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting (see Note 2). As TLP was previously a consolidated entity, our unaudited condensed consolidated statements of operations for the three months and nine months ended December 31, 2015 included TLP’s operations and income attributable to the noncontrolling interests of TLP. On April 1, 2016, we sold all of the TLP common units we owned to ArcLight (see Note 2).

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

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

sheet at March 31, 2016 was derived from our audited consolidated financial statements for the fiscal year ended March 31, 2016 included in our Annual Report on Form 10-K (“Annual Report”).

As previously reported, subsequent to the issuance of certain previously issued financial statements, in the fourth quarter of fiscal year 2016, we determined that there were errors in those financial statements from not recording certain contingent consideration liabilities related to royalty agreements assumed as part of acquisitions in our Water Solutions segment. The effect of the error was material to the financial statements for each of the first three quarters of the fiscal year ended March 31, 2016, so those quarters have been restated for the effects of the error correction. We have restated our previously issued unaudited condensed consolidated statements of operations and unaudited condensed consolidated statements of comprehensive income (loss) for the three months and nine months ended December 31, 2015 and unaudited condensed consolidated statement of cash flows for the nine months ended December 31, 2015. See Note 17 in our Annual Report for a summary of the impact of the error correction for the three months and nine months ended December 31, 2015.

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, 2017.

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 assets, the fair value of asset retirement obligations, the value of equity-based compensation, and accruals for various commitments and contingencies. 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. 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.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

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 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 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.

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. We include amounts billed to customers for shipping and handling costs in revenues in our unaudited condensed consolidated statements of operations. We enter into certain contracts whereby we agree to purchase product from a counterparty and sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into at the same time and in contemplation of each other, we record the revenues for these transactions net of cost of sales.

Revenues during the three months ended December 31, 2016 and 2015 include $1.2 million and $1.5 million, respectively, and revenues during the nine months ended December 31, 2016 and 2015 include $3.7 million and $4.4 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.

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

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

replacement cost using prices at the end of the reporting period. In performing this analysis, we consider fixed-price forward commitments and the opportunity to transfer propane inventory from our wholesale Liquids business to our Retail Propane business to sell the inventory in retail markets.

Inventories consist of the following at the dates indicated:



	December 31, 2016		March 31, 2016
	(in thousands)
Crude oil	$	95,011	$	84,030
Natural gas liquids:
Propane	86,909		28,639
Butane	22,452		8,461
Other	4,724		6,011
Refined products:
Gasoline	164,570		80,569
Diesel	177,039		99,398
Renewables	53,563		52,458
Other	9,725		8,240
Total	$	613,993	$	367,806

Investments in Unconsolidated Entities

Investments we cannot control, but can exercise significant influence over, are 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.

On April 1, 2016, we sold all of the TLP common units we owned to ArcLight for approximately $112.4 million in cash and recorded a gain on disposal of $104.1 million during the nine months ended December 31, 2016.

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



Entity	Segment	Ownership Interest	Date Acquired or Formed	December 31, 2016		March 31, 2016
				(in thousands)
Glass Mountain (1)	Crude Oil Logistics	50%	December 2013	$	172,065	$	179,594
Ethanol production facility	Refined Products and Renewables	19%	December 2013	12,921		12,570
Water treatment and disposal facility	Water Solutions	50%	August 2015	2,159		2,238
Retail propane company	Retail Propane	50%	April 2015	369		972
TLP (2)	Refined Products and Renewables	0%	July 2014	—		8,301
Freshwater supply company (3)	Water Solutions	100%	June 2014	—		15,875
Total				$	187,514	$	219,550

(1)

When we acquired Gavilon, LLC, (“Gavilon Energy”), we recorded the investment in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oil pipeline in Oklahoma, at fair value. Our investment in Glass Mountain exceeds our proportionate share of the historical net book value of Glass Mountain’s net assets by $73.1 million at December 31, 2016. This difference relates primarily to goodwill and customer relationships.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015


(2)	On April 1, 2016, we sold all of the TLP common units we owned.


(3)	On June 3, 2016, we acquired the remaining 65% ownership interest in the freshwater supply company, and as a result, the freshwater supply company was consolidated in our unaudited condensed consolidated financial statements (see Note 4). On November 29, 2016, we sold this freshwater supply company.

Other Noncurrent Assets

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



	December 31, 2016		March 31, 2016
	(in thousands)
Loan receivable (1)	$	42,410	$	49,827
Tank bottoms (2)	42,044		42,044
Line fill (3)	43,015		35,060
Other	123,900		49,108
Total	$	251,369	$	176,039


(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)

Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms when the storage tanks are removed from service. At December 31, 2016 and March 31, 2016, 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).


(3)	Represents minimum volumes of crude oil we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At December 31, 2016 and March 31, 2016, line fill consisted of 582,807 barrels and 487,104 barrels of crude oil, respectively.

Accrued Expenses and Other Payables

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



	December 31, 2016		March 31, 2016
	(in thousands)
Accrued compensation and benefits	$	16,539	$	40,517
Excise and other tax liabilities	55,451		59,455
Derivative liabilities	40,813		28,612
Accrued interest	27,767		20,543
Product exchange liabilities	9,355		5,843
Deferred gain on sale of general partner interest in TLP	30,113		30,113
Other	15,995		29,343
Total	$	196,033	$	214,426

Sale of General Partner Interest in TLP

As previously reported, on February 1, 2016, we completed the sale of our general partner interest in TLP to ArcLight and 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 and nine months ended December 31, 2016, we recognized $7.5 million and $22.6 million, respectively, of the deferred gain in our unaudited condensed consolidated statements of operations. Within our 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, $146.8 million, is recorded in other noncurrent liabilities.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Noncontrolling Interests

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

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 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 three months ended December 31, 2016 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, 2016.

In September 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-16, “Simplifying the Accounting Adjustments for Measurement-Period Adjustments.” The ASU requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. This ASU requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The ASU was effective for the Partnership beginning April 1, 2016, and required a prospective method of adoption.

Reclassifications

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

Recent Accounting Pronouncements

In 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. 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 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 in the process of assessing the impact of this ASU on our consolidated financial statements.

In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory.” The ASU requires that inventory within the scope of the guidance be measured at the lower of cost or net realizable value. The ASU is effective for the Partnership beginning April 1, 2017, and requires a prospective method of adoption, although early adoption is permitted. We do not expect the adoption of this ASU to have a material impact on our consolidated financial position or results of operations.

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

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

methods of adoption. We are in the process of determining the method of adoption and assessing the impact of this ASU on our consolidated financial statements.

Note 3—Income (Loss) Per Common Unit

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



				As Restated						As Restated
	Three Months Ended December 31,						Nine Months Ended December 31,
	2016			2015			2016			2015
	(in thousands, except unit and per unit amounts)
Net income	$	1,293		$	50,995		$	117,388		$	19,888
Less: Net income attributable to noncontrolling interests	(317		)	(6,838		)	(6,091		)	(14,685		)
Net income attributable to NGL Energy Partners LP	976			44,157			111,297			5,203
Less: Distributions to preferred unitholders	(8,906		)	—			(20,958		)	—
Less: Net income allocated to general partner (1)	(22		)	(16,239		)	(180		)	(47,798		)
Net (loss) income allocated to common unitholders (basic)	(7,952		)	27,918			90,159			(42,595		)
Effect of dilutive securities	—			(3,967		)	—			—
Net (loss) income allocated to common unitholders (diluted)	$	(7,952	)	$	23,951		$	90,159		$	(42,595	)
Basic (loss) income per common unit	$	(0.07	)	$	0.27		$	0.85		$	(0.41	)
Diluted (loss) income per common unit	$	(0.07	)	$	0.22		$	0.82		$	(0.41	)
Basic weighted average common units outstanding (2)	107,966,901			105,338,200			106,114,668			104,808,649
Diluted weighted average common units outstanding (2)	107,966,901			106,194,547			109,554,928			104,808,649


(1)	Net income allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights, which are discussed in Note 11.


(2)	The basic and diluted weighted average common units outstanding for the three months and nine months ended December 31, 2015 were not restated.

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



	Three Months Ended December 31,		Nine Months Ended December 31,
	2016	2015	2016	2015
Weighted average units outstanding during the period:
Common units - Basic	107,966,901	105,338,200	106,114,668	104,808,649
Effect of Dilutive Securities:
Performance units	—	—	111,826	—
Warrants	—	—	3,328,434	—
Restricted units	—	856,347	—	—
Common units - Diluted	107,966,901	106,194,547	109,554,928	104,808,649

For the nine months ended December 31, 2016, the convertible preferred units were considered antidilutive.

Note 4—Acquisitions

The following summarizes our acquisitions made during the nine months ended December 31, 2016.

Water Solutions Facilities

During the nine months ended December 31, 2016, we acquired three water solutions facilities and paid $26.9 million of cash. In addition, we have recorded contingent consideration liabilities within accrued expenses and other payables and other

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

noncurrent liabilities related to future royalty payments due to the sellers of one of these facilities. We estimated the contingent consideration based on the contracted royalty rate, which is a flat rate per disposal barrel and percentage of oil revenues, multiplied by the expected disposal volumes and oil revenue for the expected useful life of the facility and disposal well. This amount was then discounted to present value using our weighted average cost of capital plus a premium representative of the uncertainty associated with the expected disposal volumes and oil revenue. As of the acquisition date, we recorded a contingent liability of $2.6 million.

We assumed a land lease with a royalty component as part of the acquisition of one of the facilities. The acquisition method of accounting requires that executory contracts with unfavorable terms relative to market conditions at the acquisition date be recorded as assets or liabilities in the acquisition accounting. We recorded a liability to other noncurrent liabilities of $2.8 million related to this lease due to the royalty terms being deemed unfavorable. We will amortize this liability based on the volumes processed by the facility.

We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed for these water solutions facilities, and as a result, the estimates of fair value at December 31, 2016 are subject to change. The following table summarizes the preliminary estimates of the fair values of the assets acquired and liabilities assumed (in thousands):



Property, plant and equipment	$	15,636
Goodwill	12,918
Intangible assets	3,878
Current liabilities	(314		)
Other noncurrent liabilities	(5,222		)
Fair value of net assets acquired	$	26,896

Goodwill represents a premium paid to expand the number of our disposal sites in an oilfield production basin currently serviced by us, thereby enhancing our competitive position as a provider of disposal services in this oilfield production basin. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Acquisition of Remaining Interest in Water Solutions Facilities

On September 15, 2016, we acquired the remaining 25% ownership interest in three water solutions facilities and paid $10.0 million of cash. 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 25% interest had a carrying value of $7.4 million.

Water Pipeline Company

As discussed below, on January 7, 2016, we acquired a 57.125% interest in an existing produced water pipeline company operating in the Delaware Basin portion of West Texas. On June 3, 2016, we acquired an additional 24.5% interest in this water pipeline company as part of the purchase and sale agreement discussed in Note 15. As we control this entity (and continue to retain our controlling financial interest), the acquisition of the additional 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 24.5% interest had a carrying value of $5.2 million.

Freshwater Supply Company

On June 3, 2016, we acquired the remaining 65% ownership interest in a freshwater supply company (see Note 2). In exchange for this additional interest, we paid $1.0 million of cash and assumed an outstanding note payable, which relates to money this entity previously borrowed from us. Prior to the completion of this transaction, we accounted for our previously held 35% ownership interest of this freshwater supply company using the equity method of accounting (see Note 2). As we owned a controlling interest in this entity, we revalued our previously held 35% ownership interest to fair value of $0.8 million and recorded a loss of $14.9 million, which is recorded within revaluation of investments in our unaudited condensed consolidated statement of operations. 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 gain on bargain purchase of $0.6 million within revaluation of investments in our unaudited condensed consolidated statement of operations.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

The following table summarizes the fair values of the assets acquired and liabilities assumed (in thousands):



Current assets	$	1,713
Property, plant and equipment	8,874
Intangible asset	14,472
Current liabilities	(2,765		)
Notes payable-intercompany	(19,900		)
Fair value of net assets acquired	$	2,394

On November 29, 2016, we sold this freshwater supply company. We received proceeds of $22.0 million and recorded a loss on the sale of $2.3 million during the three months ended December 31, 2016.

Retail Propane Businesses

During the nine months ended December 31, 2016, we acquired four retail propane businesses and paid $81.0 million of cash and issued 218,617 common units, valued at $4.0 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 in these business combinations, and as a result, the estimates of fair value at December 31, 2016 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	$	4,467
Property, plant and equipment	35,219
Goodwill	10,286
Intangible assets	43,860
Current liabilities	(6,621		)
Other noncurrent liabilities	(2,207		)
Fair value of net assets acquired	$	85,004

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 estimate that all of the goodwill will be deductible for federal income tax purposes.

The following summarizes certain adjustments made during the nine months ended December 31, 2016, to the preliminary purchase price allocation of acquisitions made prior to April 1, 2016.

Water Pipeline Company

During the nine months ended December 31, 2016, we finalized the purchase price accounting for the 57.125% interest acquired in a water pipeline company on January 7, 2016. During the nine months ended December 31, 2016, we recorded an adjustment to reclassify approximately $1.1 million from property, plant and equipment to intangible assets, in order to present the fair value of the acquired rights-of-way as a finite-lived asset, which is consistent with our historical accounting policies, and we recorded an adjustment of $0.3 million to other noncurrent liabilities and goodwill to recognize an asset retirement obligation. In addition, we paid $1.0 million in cash to the seller during the nine months ended December 31, 2016 for consideration that was held back at the acquisition date, which we recorded as a liability to accrued expenses and other payables. There have been no other adjustments to the fair value of assets acquired and liabilities assumed which were disclosed in our Annual Report.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Delaware Basin Water Solutions Facilities

During the three months ended June 30, 2016, we finalized the purchase price accounting for the four saltwater disposal facilities and a 50% interest in an additional saltwater disposal facility in the Delaware Basin of the Permian Basin in Texas we acquired on August 24, 2015. There have been no adjustments to the fair value of assets acquired and liabilities assumed which were disclosed in our Annual Report.

Water Solutions Facilities

During the three months ended June 30, 2016, we finalized the purchase price accounting for nine water facilities acquired under the development agreement during the fiscal year ended March 31, 2016. During the nine months ended December 31, 2016, we received additional information and recorded an adjustment of $1.4 million to property, plant and equipment and goodwill to recognize the fair value of additional assets that we acquired. In addition, we paid $1.0 million in cash to the seller during the three months ended June 30, 2016 for consideration that was held back at the acquisition date, which we recorded as a liability to accrued expenses and other payables.

Retail Propane Businesses

During the nine months ended December 31, 2016, we finalized the purchase price accounting for five retail propane businesses we acquired during the fiscal year ended March 31, 2016 and paid $0.5 million in cash to sellers during the nine months ended December 31, 2016 for consideration that was held back at the acquisition date, which we recorded as a liability to accrued expenses and other payables.

Note 5—Property, Plant and Equipment

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



Description	Estimated Useful Lives	December 31, 2016			March 31, 2016
		(in thousands)
Natural gas liquids terminal and storage assets	2–30 years	$	171,186		$	169,758
Pipeline and related facilities	30–40 years	220,207			—
Refined products terminal assets and equipment	20 years	6,736			6,844
Retail propane equipment	2–30 years	233,643			201,312
Vehicles and railcars	3–25 years	196,798			185,547
Water treatment facilities and equipment	3–30 years	550,928			508,239
Crude oil tanks and related equipment	2–40 years	182,872			137,894
Barges and towboats	5–40 years	89,084			86,731
Information technology equipment	3–7 years	41,298			38,653
Buildings and leasehold improvements	3–40 years	150,966			118,885
Land		49,276			47,114
Tank bottoms		12,093			20,355
Other	3–30 years	47,051			11,699
Construction in progress		142,923			383,032
		2,095,061			1,916,063
Accumulated depreciation		(348,136		)	(266,491		)
Net property, plant and equipment		$	1,746,925		$	1,649,572

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

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



	Three Months Ended December 31,				Nine Months Ended December 31,
	2016		2015		2016		2015
	(in thousands)
Depreciation expense	$	32,039	$	35,443	$	88,396	$	105,707
Capitalized interest expense	$	1,429	$	761	$	6,233	$	1,451



	December 31, 2016			March 31, 2016
Product	Volume (in barrels) (in thousands)	Value (in thousands)		Volume (in barrels) (in thousands)	Value (in thousands)
Crude oil	132	$	11,108	231	$	19,348
Other	27	985		24	1,007
Total		$	12,093		$	20,355

Loss on Disposal of Assets

During the three months and nine months ended December 31, 2016, we recorded losses of $5.2 million and $16.0 million, respectively, due primarily to the sales and write-down of certain assets in our Crude Oil Logistics, Water Solutions and Refined Products and Renewables segments. During the three months and nine months ended December 31, 2015, we recorded losses of $0.2 million and $1.9 million, respectively, due primarily to the sales of certain assets in our Crude Oil Logistics and Water Solutions segments. These losses are reported within loss (gain) on disposal or impairment of assets, net in our unaudited condensed consolidated statements of operations.

Note 6—Goodwill

The following table summarizes changes in goodwill by segment during the nine months ended December 31, 2016:



	Crude Oil Logistics		Water Solutions			Liquids		Retail Propane			Refined Products and Renewables		Total
	(in thousands)
Balances at March 31, 2016	$	579,846	$	290,915		$	266,046	$	127,428		$	51,127	$	1,315,362
Revisions to acquisition accounting (Note 4)	—		(1,110		)	—		(2		)	—		(1,112		)
Acquisitions (Note 4)	—		12,918			—		10,286			—		23,204
Adjustment to initial impairment estimate	—		124,662			—		—			—		124,662
Balances at December 31, 2016	$	579,846	$	427,385		$	266,046	$	137,712		$	51,127	$	1,462,116

Goodwill Adjustment to Initial Impairment Estimate

During the three months ended March 31, 2016, we recorded a preliminary goodwill impairment charge of $380.2 million. During the three months ended June 30, 2016, we finalized our goodwill impairment analysis, with the assistance of a third party valuation firm. As a result of finalizing our analysis, we determined that we needed to reverse $124.7 million of the previously recorded goodwill impairment recorded during the three months ended March 31, 2016. The reversal was due primarily to the change in the fair value of our customer relationship intangible assets. With the assistance of the third party valuation firm, inputs such as revenue growth rates and attrition rates related to existing customers were refined and resulted in a lower fair value allocated to customer relationships than in our preliminary calculation. We recorded the reversal within loss (gain) on disposal or impairment of assets, net in our unaudited condensed consolidated statement of operations.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Note 7—Intangible Assets

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



		December 31, 2016						March 31, 2016
Description	Amortizable Lives	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
		(in thousands)
Amortizable:
Customer relationships	3–20 years	$	889,496	$	294,652	$	594,844	$	852,118	$	233,838	$	618,280
Customer commitments	10 years	310,000		5,167		304,833		—		—		—
Pipeline capacity rights	30 years	161,786		10,304		151,482		119,636		6,559		113,077
Rights-of-way and easements	1–40 years	61,888		1,295		60,593		—		—		—
Water facility development agreement	5 years	—		—		—		14,000		7,700		6,300
Executory contracts and other agreements	5–30 years	22,713		20,114		2,599		23,920		21,075		2,845
Non-compete agreements	2–32 years	32,784		16,395		16,389		20,903		13,564		7,339
Trade names	1–10 years	15,439		13,305		2,134		15,439		12,034		3,405
Debt issuance costs (1)	3 years	39,980		27,285		12,695		39,942		22,108		17,834
Total amortizable		1,534,086		388,517		1,145,569		1,085,958		316,878		769,080
Non-amortizable:
Customer commitments (2)		—		—		—		310,000		—		310,000
Rights-of-way and easements (2)		—		—		—		47,190		—		47,190
Trade names		19,180		—		19,180		22,620		—		22,620
Total non-amortizable		19,180		—		19,180		379,810		—		379,810
Total		$	1,553,266	$	388,517	$	1,164,749	$	1,465,768	$	316,878	$	1,148,890


(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.


(2)	Amounts moved to the amortizable section above due to the related assets being placed in service during the three months ended December 31, 2016.

The weighted-average remaining amortization period for intangible assets is approximately 9.1 years.

Write off of Intangible Assets

As a result of terminating the development agreement in the Water Solutions segment (see Note 15), we incurred a loss of $5.8 million to write off the water facility development agreement. During the three months ended June 30, 2016, we wrote-off $5.2 million related to the value of an indefinite-lived trade name intangible asset in conjunction with finalizing our goodwill impairment analysis (see Note 6). These losses are reported within loss (gain) on disposal or impairment of assets, net in our unaudited condensed consolidated statement of operations.

Amortization expense is as follows for the periods indicated:



	Three Months Ended December 31,				Nine Months Ended December 31,
Recorded In	2016		2015		2016		2015
	(in thousands)
Depreciation and amortization	$	28,728	$	23,737	$	71,880	$	70,065
Cost of sales	1,753		1,701		5,098		5,102
Interest expense	1,721		4,834		5,177		7,788
Total	$	32,202	$	30,272	$	82,155	$	82,955

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

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



Year Ending March 31,
2017 (three months)	$	33,822
2018	132,843
2019	123,129
2020	115,343
2021	102,541
Thereafter	637,891
Total	$	1,145,569

Note 8—Long-Term Debt

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



	December 31, 2016							March 31, 2016
	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	$	638,000	$	—		$	638,000	$	1,229,500	$	—		$	1,229,500
Working capital borrowings	875,500		—			875,500		618,500		—			618,500
5.125% Notes due 2019	383,467		(3,595		)	379,872		388,467		(4,681		)	383,786
6.875% Notes due 2021	369,063		(6,186		)	362,877		388,289		(7,545		)	380,744
6.650% Notes due 2022	250,000		(2,929		)	247,071		250,000		(3,166		)	246,834
7.500% Notes due 2023	700,000		(11,750		)	688,250		—		—			—
Other long-term debt	58,550		(114		)	58,436		61,488		(108		)	61,380
	3,274,580		(24,574		)	3,250,006		2,936,244		(15,500		)	2,920,744
Less: Current maturities	33,501		—			33,501		7,907		—			7,907
Long-term debt	$	3,241,079	$	(24,574	)	$	3,216,505	$	2,928,337	$	(15,500	)	$	2,912,837


(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 $1.2 million and $0.8 million during the three months ended December 31, 2016 and 2015, respectively, and $3.0 million and $2.4 million during the nine months ended December 31, 2016 and 2015, respectively.

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



Year Ending March 31,
2017 (three months)	$	1,304
2018	5,077
2019	4,937
2020	3,953
2021	3,539
Thereafter	5,764
Total	$	24,574

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Credit Agreement

We have entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). At December 31, 2016, our Revolving Credit Facility had a total capacity of $2.484 billion. Our Revolving Credit Facility has an “accordion” feature that allows us to increase the capacity by $150 million if new lenders wish to join the syndicate or if current lenders wish to increase their commitments.

The Expansion Capital Facility had a total capacity of $1.446 billion for cash borrowings at December 31, 2016. At that date, we had outstanding borrowings of $638.0 million on the Expansion Capital Facility. The Working Capital Facility had a total capacity of $1.038 billion for cash borrowings and letters of credit at December 31, 2016. At that date, we had outstanding borrowings of $875.5 million and outstanding letters of credit of $79.6 million on the Working Capital Facility. Amounts outstanding for letters of credit are not recorded as long-term debt on our unaudited condensed consolidated balance sheets, although they decrease our borrowing capacity under the Working Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base” (as defined in the Credit Agreement), which is calculated based on the value of certain working capital items at any point in time.

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

All borrowings under the Credit Agreement bear interest, at our option, at either (i) an alternate base rate plus a margin of 0.50% to 1.75% per year or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.75% per year. The applicable margin is determined based on our consolidated leverage ratio (as defined in the Credit Agreement). At December 31, 2016, the borrowings under the Credit Agreement had a weighted average interest rate of 3.39%, calculated as the weighted LIBOR rate of 0.74% plus a margin of 2.50% for LIBOR borrowings and the prime rate of 3.75% plus a margin of 1.50% on alternate base rate borrowings. At December 31, 2016, the interest rate in effect on letters of credit was 2.50%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused capacity.

The Revolving Credit Facility is secured by substantially all of our assets. The Credit Agreement also specifies that our leverage ratio cannot be more than 4.75 to 1 and that our interest coverage ratio cannot be less than 2.75 to 1 at any quarter end. At December 31, 2016, our leverage ratio was approximately 4.50 to 1 and our interest coverage ratio was approximately 3.94 to 1.

At December 31, 2016, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

On July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the “2019 Notes”). During the three months ended June 30, 2016, we repurchased $5.0 million of our 2019 Notes for an aggregate purchase price of $3.1 million (excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2019 Notes of $1.8 million (net of the write off of debt issuance costs of $0.1 million).

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

At December 31, 2016, we were in compliance with the covenants under the indenture governing the 2019 Notes.

2021 Notes

On October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the “2021 Notes”). During the three months ended June 30, 2016, we repurchased $19.2 million of our 2021 Notes for an aggregate purchase price of $12.0 million (excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2021 Notes of $6.8 million (net of the write off of debt issuance costs of $0.4 million).

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

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

At December 31, 2016, we were in compliance with the covenants under the indenture governing the 2021 Notes.

2022 Notes

On June 19, 2012, we entered into a Note Purchase Agreement (as amended, the “2022 Note Purchase Agreement”) whereby we issued $250.0 million of Senior Notes in a private placement (the “2022 Notes”). The 2022 Notes bear interest at a fixed rate of 6.65%, which is payable quarterly. The 2022 Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to prepay outstanding principal, although we would incur a prepayment penalty. On September 30, 2016, we amended our Note Purchase Agreement which, among other things, changes the maximum allowable leverage ratio to match the maximum allowable leverage ratio and the calculation of such ratio under our Credit Agreement. Additionally, the amendment provides for an increase in interest charged should our leverage ratio exceed certain predetermined levels. The 2022 Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

At December 31, 2016, we were in compliance with the covenants under the 2022 Note Purchase Agreement.

2023 Notes

On October 24, 2016, we entered into a Note Purchase Agreement (as amended, the “2023 Note Purchase Agreement”) whereby we issued $700.0 million of Senior Unsecured Notes (the “2023 Notes”) in a private placement. The 2023 Notes bear interest at 7.50%, which is payable on May 1 and November 1 of each year, beginning on May 1, 2017. We received net proceeds of $687.9 million, after the initial purchasers’ discount of $10.5 million and offering costs of $1.6 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility. The 2023 Notes mature on November 1, 2023.

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2023 Notes, and the obligations under the 2023 Notes are fully and unconditionally guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The indenture governing the 2023 Notes contains various customary covenants, including, (i) pay distributions on, purchase or redeem our common equity or purchase or redeem our subordinated debt, (ii) incur or guarantee additional indebtedness or issue preferred units, (iii) create or incur certain liens, (iv) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us, (v) consolidate, merge or transfer all or substantially all of our assets, and (vi) engage in transactions with affiliates.

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

We have the option to redeem all or a portion of the 2023 Notes at any time on or after November 1, 2019 at 100% of the principal amount of the 2023 Notes redeemed plus accrued and unpaid interest. Prior to November 1, 2019, the Partnership may redeem all or a portion of the 2023 Notes at a price equal to the “make whole price” specified in the indenture, plus accrued and unpaid interest.

In connection with the closing of the offering of the 2023 Notes, the Partnership entered into a registration rights agreement (the “Registration Rights Agreement”). Under the Registration Rights Agreement, the Partnership agreed to file a registration statement with the SEC so that holders can exchange the 2023 Notes for registered notes that have substantially identical terms as the 2023 Notes and evidence the same indebtedness as the 2023 Notes. In addition, the subsidiary guarantors agreed to exchange the guarantee related to the 2023 Notes for a registered guarantee having substantially the same terms as the original guarantees. The Partnership is obligated use their commercially reasonable efforts to file an exchange offer registration statement with respect to the exchange notes and the exchange guarantees and cause such exchange offer registration statement to become effective on or prior to 365 days after the closing of this offering. If the Partnership fails to satisfy these obligations, it will be required to pay to the holders of the 2023 Notes liquidated damages in an amount equal to 0.25% per annum on the principal amount of the 2023 Notes held by such holder during the 90-day period immediately following the occurrence of such registration default, and such amount shall increase by 0.25% per annum at the end of such 90-day period.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

At December 31, 2016, we were in compliance with the covenants under the 2023 Note Purchase Agreement.

Other Long-Term Debt

We have certain notes payable related to equipment financing. We have also 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 combined principal balance of $58.6 million at December 31, 2016, and the interest rates on these instruments range from 1.17% to 7.08% per year.

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at December 31, 2016:



Year Ending March 31,	Revolving Credit Facility		2019 Notes		2021 Notes		2022 Notes		2023 Notes		Other Long-Term Debt		Total
	(in thousands)
2017 (three months)	$	—	$	—	$	—	$	—	$	—	$	1,437	$	1,437
2018	—		—		—		25,000		—		8,234		33,234
2019	1,513,500		—		—		50,000		—		7,106		1,570,606
2020	—		383,467		—		50,000		—		6,594		440,061
2021	—		—		—		50,000		—		34,902		84,902
Thereafter	—		—		369,063		75,000		700,000		277		1,144,340
Total	$	1,513,500	$	383,467	$	369,063	$	250,000	$	700,000	$	58,550	$	3,274,580

Note 9—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. Our fiscal years 2013 to 2016 generally remain subject to examination by federal, state, and Canadian tax authorities. We utilize the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.

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

We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in our unaudited condensed consolidated financial statements at December 31, 2016 or March 31, 2016.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Note 10—Commitments and Contingencies

Legal Contingencies

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

Environmental Matters

Our unaudited condensed consolidated balance sheet at December 31, 2016 includes a liability, measured on an undiscounted basis, of $2.4 million related to environmental matters, which is reported within accrued expenses and other payables. 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 (hereafter referred to as “Gavilon”) of alleged violations in 2011 by Gavilon of the Clean Air Act’s renewable fuel standards regulations (prior to its acquisition by NGL 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 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 and Western Dubuque and the generation of biodiesel renewable identification numbers (“RINs”) sold by Western Dubuque to Gavilon 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, an order 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. Consistent with our position against the previous EPA allegations, and the original complaint, we deny the allegations in this amended civil complaint and intend to continue vigorously defending ourselves in the civil action. However, at this time NGL is unable to determine the outcome of this action or its significance to us.

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, 2016	$	5,574
Liabilities incurred	713
Liabilities assumed in acquisitions	406
Liabilities settled	(19		)
Accretion expense	351
Balance at December 31, 2016	$	7,025

In addition to the obligations discussed 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

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

estimated because the settlement dates are indeterminable. We will record an asset retirement obligation for these assets in the periods in which settlement dates are reasonably determinable.

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment. The following table summarizes future minimum lease payments under these agreements at December 31, 2016 (in thousands):



Year Ending March 31,
2017 (three months)	$	34,952
2018	134,262
2019	111,760
2020	100,450
2021	87,197
Thereafter	140,153
Total	$	608,774

Rental expense relating to operating leases was $32.0 million and $25.5 million during the three months ended December 31, 2016 and 2015, respectively, and $88.9 million and $92.6 million during the nine months ended December 31, 2016 and 2015, respectively.

Pipeline Capacity Agreements

We have executed noncancelable agreements with crude oil and refined products pipeline operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity. The following table summarizes future minimum throughput payments under these agreements at December 31, 2016 (in thousands):



Year Ending March 31,
2017 (three months)	$	13,534
2018	54,365
2019	53,688
2020	43,856
2021	1,438
Thereafter	599
Total	$	167,480

Construction Commitments

At December 31, 2016, we had construction commitments of $43.7 million.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

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. The following table summarizes such commitments at December 31, 2016:



	Volume	Value
	(in thousands)
Purchase commitments:
Natural gas liquids fixed-price (gallons)	17,131	$	9,504
Natural gas liquids index-price (gallons)	322,711	$	242,996
Crude oil fixed-price (barrels)	3,671	$	186,499
Crude oil index-price (barrels)	33,327	$	1,455,775
Sale commitments:
Natural gas liquids fixed-price (gallons)	119,108	$	82,791
Natural gas liquids index-price (gallons)	205,672	$	197,433
Crude oil fixed-price (barrels)	4,797	$	240,874
Crude oil index-price (barrels)	15,157	$	809,785

We account for the contracts in the table 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 table above may have offsetting derivative contracts (see Note 12) or inventory positions (see 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 table above. These contracts are included in the derivative disclosures (see Note 12), and represent $50.2 million of our prepaid expenses and other current assets and $39.9 million of our accrued expenses and other payables at December 31, 2016.

Note 11—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 ATM Program (as defined herein), as discussed within this note, as well as common units issued for a retail propane acquisition (see Note 4) during the nine months ended December 31, 2016, we issued 2,575 notional units to our general partner for $0.1 million in order to maintain its 0.1% interest in us.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Our Distributions

The following table summarizes distributions declared during the last four quarters:



Date Declared	Record Date	Date Paid/Payable	Amount Per Unit		Amount Paid/Payable to Limited Partners		Amount Paid/Payable to General Partner
					(in thousands)		(in thousands)
April 21, 2016	May 3, 2016	May 13, 2016	$	0.3900	$	40,626	$	70
July 22, 2016	August 4, 2016	August 12, 2016	$	0.3900	$	41,146	$	71
October 20, 2016	November 4, 2016	November 14, 2016	$	0.3900	$	41,907	$	72
January 19, 2017	February 3, 2017	February 14, 2017	$	0.3900	$	42,923	$	74

Class A Convertible Preferred Units

On April 21, 2016, we entered into a private placement agreement to issue $200 million of 10.75% Class A Convertible Preferred Units (“Preferred Units”) to Oaktree Capital Management L.P. and its co-investors (“Oaktree”). On June 23, 2016, the private placement agreement was amended to increase the aggregate principal amount from $200 million to $240 million. On May 11, 2016, we received an initial $100 million (“initial closing date”) and Oaktree received 8,309,237 Preferred Units, and on June 24, 2016, we received the remaining $140 million (“second closing date”) and Oaktree received 11,632,932 Preferred Units. In addition, Oaktree received 4,375,112 warrants (1,822,963 at the initial closing date and 2,552,149 at the second closing date) to purchase common units at an exercise price of $0.01 per common unit.

We will pay a cumulative, quarterly distribution in arrears at an annual rate of 10.75% on the Preferred Units then outstanding in cash, to the extent declared by the board of directors of our general partner. To the extent declared, such distributions will be paid for each such quarter within 45 days after each quarter end. On July 22, 2016, we declared a pro rata distribution for the three months ended June 30, 2016 of $1.8 million which was paid to the holders of the Preferred Units on August 12, 2016. On October 20, 2016, we declared a distribution for the three months ended September 30, 2016 of $6.4 million which was paid to the holders of the Preferred Units on November 14, 2016. On January 19, 2017, we declared a distribution for the three months ended December 31, 2016 of $6.4 million to be paid to the holders of the Preferred Units on February 14, 2017.

If the Preferred Unit quarterly distribution is not made in full in cash for any quarter, the Preferred Unit distribution rate will increase by one quarter of a percentage point (0.25%) per annum beginning with distributions for the first six-month period that a payment default is in effect, and will further increase by an additional one quarter of a percentage point (0.25%) beginning with distributions for the next six-month period during which a payment default remains in effect. The deficiency rate shall not exceed 11.25% per annum; as long as the default is occurring, the amount of accrued but unpaid Preferred Unit quarterly distributions shall increase at an annual rate of 10.75%, compounded quarterly, until paid in full.

The Preferred Units have no mandatory redemption date but are redeemable, at our election, any time after the first anniversary of the closing date. We have the right to redeem all of the outstanding Preferred Units at a price per Preferred Unit equal to the purchase price multiplied by the redemption multiple then in effect. The redemption multiple means (a) 140% for redemptions occurring on or after the first, but prior to the second anniversary of the closing date, (b) 115% for redemptions occurring on or after the second, but prior to the third anniversary of the closing date, (c) 110% for redemptions occurring on or after the third, but prior to the eighth anniversary of the closing date and (d) 101% for redemptions occurring on or after the eighth anniversary of the closing date.

At any time after the third anniversary of the initial closing date, the Preferred Unit holders shall have the right to convert all of the outstanding Preferred Units at a price per Preferred Unit equal to the purchase price multiplied by the conversion multiple then in effect, which may be settled in common units, cash or a combination, at our discretion. The conversion multiple means if our common units are trading at or above $12.035 (“the initial conversion price”), the conversion price is not adjusted. However, if the conversion price is less than the initial conversion price, the conversion price will be reset to the greater of (i) the adjusted volume weighted average price of our common units for the fifteen trading days immediately preceding the third anniversary of the closing date or (ii) $5.00.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Upon a change of control of the Partnership, each Preferred Unit holder shall have the right, at its election, to either (i) elect to have its Preferred Units converted to common units; (ii) if we are the surviving entity of such change of control, it can elect to continue to hold its Preferred Units; or (iii) require us to redeem its Preferred Units for cash equal to (a) prior to the first anniversary of the closing date, 140% of the unit purchase price; (b) on or after the first but prior to the second anniversary of the closing date, 130% of the unit purchase price; (c) on or after the second anniversary of the closing date, 120% of the unit purchase price; and (d) thereafter, 101% of the unit purchase price. In each case, this amount will include any accrued but unpaid distributions at the redemption date.

Under the private placement agreement, we are required to file within 180 days of the initial closing date a registration statement registering the resales of common units issued or to be issued upon conversion of the Preferred Units or exercise of the warrants and have the registration statement declared effective within 360 days after the closing date. We are required to continue to maintain the effectiveness of the registration statement until all securities have been sold. The Partnership’s filed registration statement was declared effective by the SEC on November 23, 2016.

The warrants have an eight year term, after which unexercised warrants will expire. 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 of the original issue date and the final one-third may be converted from and after the third anniversary. Upon a change of control or in the event we exercise our redemption right with respect to the Preferred Units, all unvested warrants shall immediately vest and be exercisable in full.

We received net proceeds of $235.0 million (net of offering costs of $5.0 million) in connection with the issuance of the Preferred Units and warrants. We allocated these net proceeds, on a relative fair value basis, to the Preferred Units ($186.4 million), which includes the value of the beneficial conversion feature, and warrants ($48.6 million). As discussed below, $131.5 million of the amount allocated to the Preferred Units was allocated to the intrinsic value of the beneficial conversion feature. A beneficial conversion feature is defined as a nondetachable conversion feature that is in the money at the commitment date. Per the applicable accounting guidance, we are required to allocate a portion of the proceeds allocated to the Preferred Units to the beneficial conversion feature based on the intrinsic value of the beneficial conversion feature. The intrinsic value is calculated at the commitment date based on the difference between the fair value of the common units at the issuance date (number of common units issuable at conversion multiplied by the per unit value of our common units at the issuance date) and the proceeds attributed to the Preferred Units. We record the accretion attributable to the beneficial conversion feature as a deemed distribution using the effective interest method over the three year period prior to the effective dates of the holders’ conversion right. Accretion for the beneficial conversion feature was $2.5 million for the three months ended December 31, 2016 and $6.3 million for the nine months ended December 31, 2016.

As discussed above, the Preferred Units are not mandatorily redeemable but are redeemable upon a change of control, which was not certain to occur at the issuance of the Preferred Units. Due to the redemption being conditioned upon an event that is not certain to occur or that is not under our control, we are required to record the value allocated to the Preferred Units, excluding the value of the beneficial conversion feature, between liabilities and equity (mezzanine or temporary equity) within our unaudited condensed consolidated balance sheet. The value allocated to the warrants and the beneficial conversion feature was recorded as part of Limited Partners’ equity within our unaudited condensed consolidated balance sheet.

Amended and Restated Partnership Agreement

On June 24, 2016, NGL Energy Holdings LLC executed the Third Amended and Restated Agreement of Limited Partnership. The preferences, rights, powers and duties of holders of the Preferred Units are defined in the amended and restated partnership agreement. The 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. The Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless redeemed by the Partnership or converted into common units at the election of the Partnership or the Preferred Unit holders or in connection with a change of control.

At-The-Market Program

On August 24, 2016, we entered into an equity distribution program in connection with an at-the-market program (the “ATM Program”) pursuant to which we may issue and sell common units for up to $200.0 million in gross proceeds. This ATM Program is registered with the SEC on an effective registration statement on Form S-3. During the nine months ended December 31,

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

2016, we sold 2,353,438 common units for net proceeds of $43.9 million (net of offering costs of $0.3 million). As of December 31, 2016, approximately $155.4 million remained available for sale under the Partnership’s ATM Program.

Subsequent to December 31, 2016, we sold an additional 967,697 common units for net proceeds of $20.5 million (net of offering costs of $0.2 million).

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 awards that vest contingent on the continued service of the recipients through the vesting date (the “Service Awards”). The restricted units also include awards that are 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”).

During the three months ended September 30, 2016, we changed our process for how taxes are withheld upon the vesting of restricted units. Previously, employees could choose to pay cash for their portion of the taxes or have us withhold enough units to meet their tax withholding requirements. Employees could also elect to have the units withheld to exceed the statutory minimums. Now, employees will still be able to pay cash to satisfy their tax obligation or they can elect to sell enough units, through a broker assisted cashless exercise program, to meet their tax obligation. As a result of this change in process, the unvested restricted units and future grants are eligible for equity classification. Prior to this change in process, we classified any Service Awards or Performance Awards granted as liabilities and were required to recalculate the fair value of the award at each reporting date. Awards classified as equity are valued only at their grant date and are not revalued at each reporting date. As of June 30, 2016, we had liabilities related to our Service Awards and Performance Awards of $25.6 million and $1.8 million, respectively, which we reclassified to equity.

The following table summarizes the Service Award activity during the nine months ended December 31, 2016:



Unvested Service Award units at March 31, 2016	2,297,132
Units granted	3,105,600
Units vested and issued	(2,350,082	)
Units forfeited	(339,600	)
Unvested Service Award units at December 31, 2016	2,713,050

The following table summarizes the scheduled vesting of our unvested Service Award units at December 31, 2016:



Year Ending March 31,
2018		881,350
2019		917,800
Thereafter		913,900
Total		2,713,050

Service Awards are valued at the market price as of the date of grant 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 must at least equal the portion of the grant-date value of the award that is vested at that date. During the three months ended December 31, 2016 and 2015, we recorded compensation expense related to Service Award units of $4.8 million and $0.4 million, respectively. During the nine months ended December 31, 2016 and 2015, we recorded compensation expense related to Service Award units of $51.5 million and $33.8 million, respectively.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Of the restricted units granted and vested during the nine months ended December 31, 2016, 1,008,091 units were granted as a bonus for performance during the fiscal year ended March 31, 2016. We accrued expense of $16.8 million during the fiscal year ended March 31, 2016 as an estimate of the value of such bonus units that would be granted. During the nine months ended December 31, 2016, we recorded an additional $2.2 million to true up the estimate to the $19.0 million of actual expense associated with these bonuses. Since the units were not formally granted until August 2016, the full $19.0 million is reflected in the expense during the three months and nine months ended December 31, 2016 in the amounts in the preceding paragraph above.

The following table summarizes the estimated future expense we expect to record on the unvested Service Award units at December 31, 2016 (in thousands):



Year Ending March 31,
2017 (three months)	$	4,676
2018	12,510
2019	9,106
Thereafter	2,386
Total	$	28,678

During April 2015, our general partner granted Performance Award units to certain employees. The number of Performance Award units that will vest is contingent on the performance of our common units relative to the performance of the other entities in the Index. Performance will be calculated based on the return on our common units (including changes in the market price of the common units and distributions paid during the performance period) relative to the returns on the common units of the other entities in the Index. As of December 31, 2016, performance will be measured over the following periods:



Vesting Date of Tranche		Performance Period for Tranche
July 1, 2017		July 1, 2014 through June 30, 2017
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 percentage of the maximum Performance Award units that will vest depending on the percentage of entities in the Index that NGL outperforms:



Our Relative Total Unitholder Return Percentile Ranking		Payout (% of Target Units)
Less than 50th percentile		0%
Between the 50th and 75th percentile		50%–100%
Between the 75th and 90th percentile		100%–200%
Above the 90% percentile		200%

The following table summarizes the Performance Award activity during the nine months ended December 31, 2016:



Unvested Performance Award units at March 31, 2016	637,382
Units granted	932,309
Units forfeited	(380,691	)
Unvested Performance Award units at December 31, 2016	1,189,000

During the July 1, 2013 through June 30, 2016 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 units vested on July 1, 2016 and are considered to be forfeited.

The fair value of the Performance Awards is estimated using a Monte Carlo simulation at the grant date. We record the expense for each of the tranches of the Performance Awards on a straight-line basis over the period beginning with the grant date and ending with the vesting date of the tranche. Any Performance Awards that do not become earned Performance Awards shall terminate, expire and otherwise be forfeited by the participants. During the three months ended December 31, 2016, and 2015, we recorded compensation expense related to Performance Award units of $2.1 million and a reversal of previously

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

recorded expense of $1.8 million, respectively, related to Performance Award units. During the nine months ended December 31, 2016 and 2015, we recorded compensation expense related to Performance Award units of $5.2 million and $16.3 million, respectively.

The following table summarizes the estimated future expense we expect to record on the unvested Performance Award units at December 31, 2016 (in thousands):



Year Ending March 31,
2017 (three months)	$	2,047
2018	6,197
2019	3,232
Thereafter	655
Total	$	12,131

The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common units. The maximum number of units deliverable under the LTIP plan automatically increases to 10% of the issued and outstanding common units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount. Units withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, when an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available for new awards under the LTIP. At December 31, 2016, approximately 1.3 million common units remain available for issuance under the LTIP.

Note 12—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:



	December 31, 2016						March 31, 2016
	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
	(in thousands)
Level 1 measurements	$	3,358		$	(75,986	)	$	47,361		$	(3,983	)
Level 2 measurements	51,054			(40,982		)	32,700			(28,612		)
	54,412			(116,968		)	80,061			(32,595		)

Netting of counterparty contracts (1)	(2,690		)	2,690			(3,384		)	3,384
Net cash collateral provided (held)	(843		)	73,465			(18,176		)	599
Commodity derivatives	$	50,879		$	(40,813	)	$	58,501		$	(28,612	)


(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

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

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



	December 31, 2016			March 31, 2016
	(in thousands)
Prepaid expenses and other current assets	$	50,879		$	58,501
Accrued expenses and other payables	(40,813		)	(28,612		)
Net commodity derivative asset	$	10,066		$	29,889

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



Contracts	Settlement Period	Net Long (Short) Notional Units (in barrels)		Fair Value of Net Assets (Liabilities)
		(in thousands)
At December 31, 2016:
Cross-commodity (1)	January 2017–March 2017	53		$	1,348
Crude oil fixed-price (2)	January 2017–March 2017	(671	)	(2,469		)
Propane fixed-price (2)	January 2017–December 2017	106		1,338
Refined products fixed-price (2)	January 2017–January 2019	(7,027	)	(66,119		)
Refined products index (2)	January 2017–December 2017	(24	)	(197		)
Other	January 2017–March 2022			3,543
				(62,556		)
Net cash collateral provided				72,622
Net commodity derivative asset				$	10,066

At March 31, 2016:
Cross-commodity (1)	April 2016–March 2017	251		$	1,663
Crude oil fixed-price (2)	April 2016–December 2016	(1,583	)	(3,655		)
Propane fixed-price (2)	April 2016–December 2017	540		(592		)
Refined products fixed-price (2)	April 2016–June 2017	(5,355	)	48,557
Other	April 2016–March 2017			1,493
				47,466
Net cash collateral held				(17,577		)
Net commodity derivative asset				$	29,889


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


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

During the three months and nine months ended December 31, 2016, we recorded net losses of $57.7 million and $102.6 million, respectively, and during the three months and nine months ended December 31, 2015, we recorded net gains of $52.5 million and $97.1 million, respectively, from our commodity derivatives to cost of sales.

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

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

industry standard master netting agreements, which allow for offsetting counterparty receivable and payable balances for certain transactions. At December 31, 2016, 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 December 31, 2016 (in thousands):



2019 Notes	$	381,070
2021 Notes	$	379,443
2022 Notes	$	277,806
2023 Notes	$	725,667

For the 2019 Notes, 2021 Notes and 2023 Notes, the fair value estimates were developed based on publicly traded quotes and would be classified as Level 1 in the fair value hierarchy. For the 2022 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.

Note 13—Segments

The following table summarizes certain financial data related to our segments for the periods indicated. 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

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015



				As Restated						As Restated
	Three Months Ended December 31,						Nine Months Ended December 31,
	2016			2015			2016			2015
	(in thousands)
Revenues:
Crude Oil Logistics:
Crude oil sales	$	366,569		$	508,863		$	1,123,169		$	2,818,752
Crude oil transportation and other	20,914			12,423			43,020			44,118
Elimination of intersegment sales	(1,577		)	(1,861		)	(4,447		)	(8,083		)
Total Crude Oil Logistics revenues	385,906			519,425			1,161,742			2,854,787
Water Solutions:
Service fees	28,268			35,138			82,493			107,079
Recovered hydrocarbons	6,387			8,414			19,264			34,978
Other revenues	5,704			1,886			14,088			5,168
Total Water Solutions revenues	40,359			45,438			115,845			147,225
Liquids:
Propane sales	260,562			188,930			458,646			393,442
Other product sales	235,739			180,620			485,174			488,967
Other revenues	7,704			8,161			22,926			27,531
Elimination of intersegment sales	(33,730		)	(24,184		)	(57,162		)	(48,436		)
Total Liquids revenues	470,275			353,527			909,584			861,504
Retail Propane:
Propane sales	96,699			68,880			174,510			148,184
Distillate sales	19,569			19,133			35,613			39,758
Other revenues	12,418			12,132			30,056			29,856
Elimination of intersegment sales	(32		)	—			(48		)	—
Total Retail Propane revenues	128,654			100,145			240,131			217,798
Refined Products and Renewables:
Refined products sales	2,258,317			1,532,928			6,409,889			4,946,136
Renewables sales	123,065			101,414			325,377			300,756
Service fees	50			32,381			11,195			89,193
Elimination of intersegment sales	(149		)	(252		)	(293		)	(729		)
Total Refined Products and Renewables revenues	2,381,283			1,666,471			6,746,168			5,335,356
Corporate and Other	164			—			679			—
Total revenues	$	3,406,641		$	2,685,006		$	9,174,149		$	9,416,670
Depreciation and Amortization:
Crude Oil Logistics	$	16,503		$	10,041		$	34,496		$	30,096
Water Solutions	27,150			23,644			76,713			66,906
Liquids	4,441			3,537			13,315			11,286
Retail Propane	11,379			9,096			31,771			26,711
Refined Products and Renewables	404			11,493			1,237			36,820
Corporate and Other	890			1,369			2,744			3,953
Total depreciation and amortization	$	60,767		$	59,180		$	160,276		$	175,772
Operating Income (Loss):
Crude Oil Logistics	$	(9,163	)	$	804		$	(28,827	)	$	12,689
Water Solutions	(11,898		)	15,596			63,136			44,300
Liquids	24,765			32,921			33,092			52,820
Retail Propane	21,772			14,450			10,553			11,985
Refined Products and Renewables	8,209			31,702			169,365			59,478
Corporate and Other	(11,128		)	(12,919		)	(66,690		)	(81,630		)
Total operating income	$	22,557		$	82,554		$	180,629		$	99,642

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

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



	Three Months Ended December 31,						Nine Months Ended December 31,
	2016			2015			2016		2015
	(in thousands)
Crude Oil Logistics	$	42,758		$	214,114		$	147,460	$	321,137
Water Solutions	18,275			57,817			86,628		190,837
Liquids	1,736			(24,576		)	14,897		11,488
Retail Propane	16,196			11,641			94,170		34,350
Refined Products and Renewables	(945		)	(4,684		)	42,175		18,599
Corporate and Other	375			12,715			2,107		13,884
Total	$	78,395		$	267,027		$	387,437	$	590,295

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



	December 31, 2016		March 31, 2016
	(in thousands)
Long-lived assets, net:
Crude Oil Logistics	$	1,721,536	$	1,679,027
Water Solutions	1,276,811		1,162,405
Liquids	573,045		572,081
Retail Propane	555,214		483,330
Refined Products and Renewables	216,906		180,783
Corporate and Other	30,278		36,198
Total	$	4,373,790	$	4,113,824

Total assets:
Crude Oil Logistics	$	2,438,956	$	2,197,113
Water Solutions	1,315,432		1,236,875
Liquids	837,989		693,872
Retail Propane	639,099		538,267
Refined Products and Renewables	1,032,683		765,806
Corporate and Other	113,917		128,222
Total	$	6,378,076	$	5,560,155

Note 14—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 an equity method investee. These transactions are reported within cost of sales in our unaudited condensed consolidated statements of operations.

Certain members of our management and members of their families as well as other associated parties own interests in entities from which we have purchased products and services and to which we have sold products and services. During the nine months ended December 31, 2016, $12.8 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

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

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



	Three Months Ended December 31,				Nine Months Ended December 31,
	2016		2015		2016		2015
	(in thousands)
Sales to SemGroup	$	150	$	67	$	3,734	$	42,098
Purchases from SemGroup	$	1,911	$	5,052	$	5,874	$	50,355
Sales to equity method investees	$	95	$	1,676	$	595	$	4,762
Purchases from equity method investees	$	33,538	$	27,153	$	91,530	$	82,917
Sales to entities affiliated with management	$	53	$	91	$	205	$	289
Purchases from entities affiliated with management	$	2,580	$	6,709	$	14,316	$	30,103

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



	December 31, 2016		March 31, 2016
	(in thousands)
Receivables from SemGroup	$	19,957	$	1,166
Receivables from equity method investees	13		14,446
Receivables from entities affiliated with management	38		13
Total	$	20,008	$	15,625

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



	December 31, 2016		March 31, 2016
	(in thousands)
Payables to SemGroup	$	20,493	$	1,823
Payables to equity method investees	1,431		3,947
Payables to entities affiliated with management	993		1,423
Total	$	22,917	$	7,193

We also have a loan receivable of $2.7 million at December 31, 2016 from an equity method investee 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.

We had a loan receivable of $22.3 million at March 31, 2016 from our freshwater supply company equity method investee. During the three months ended June 30, 2016, we received loan payments of $0.7 million from our investee in accordance with the loan agreement. On June 3, 2016, we acquired the remaining 65% ownership interest in this equity method investee (see Note 4) and this loan receivable was eliminated upon consolidation. As a result of the acquisition, we incurred an impairment charge of $1.7 million to write down the loan receivable to its fair value.

Note 15—Other Matters

Termination of an Agreement

During the three months ended December 31, 2016, we agreed to terminate a storage sublease agreement that was scheduled to commence in January 2017 and had a term of five years. For terminating this agreement, the counterparty agreed to pay us a specific amount in five equal payments beginning in February 2017 and in January of the next four years and removed any future obligations of the Partnership. As a result, we discounted the future payments and recorded a gain of $16.2 million to other income in our unaudited condensed consolidated statement of operations during the three months ended December 31, 2016.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Purchase of Pipeline Capacity Rights

On certain interstate refined product pipelines, shipment demand exceeds available capacity, and capacity is allocated to shippers based on their historical shipment volumes. During the nine months ended December 31, 2016, we paid $42.2 million to acquire certain refined product pipeline capacity rights from other shippers on the Colonial pipeline which is included in intangible assets.

Termination of Development Agreement

On June 3, 2016, we entered into a purchase and sale agreement with the counterparty to the development agreement in our Water Solutions segment (see Note 4). Total cash consideration paid under the agreement was $49.6 million and in return we received the following:


•	Termination of the development agreement (see Note 4);


•	Additional interest in the water pipeline company we acquired in January 2016 (see Note 4);


•	Release of contingent consideration liabilities (see Note 4) attributed to certain of our water treatment and disposal facilities;


•	Certain parcels of land and permits to develop saltwater disposal wells and other parcels of land containing water wells and equipment; and


•	A two-year non-compete agreement with the counterparty.

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 shall be allocated to the individual assets acquired or liabilities assumed/released based on their relative fair values and shall not give rise to goodwill or bargain purchase gains. We allocated $1.2 million of the total consideration to property, plant and equipment, $3.3 million to intangible assets, $2.8 million to noncontrolling interest, $25.5 million to the release of contingent consideration liabilities and $16.9 million to the termination of the development agreement. We recorded a $21.3 million gain on the release of $46.8 million of contingent consideration liabilities, which was recorded within gain on early extinguishment of liabilities in our unaudited condensed consolidated statement of operations during the nine months ended December 31, 2016. For the termination of the development agreement, we recorded a loss of $22.7 million, which included the carrying value of the development agreement asset that was written off (see Note 7). This loss was recorded within loss (gain) on disposal or impairment of assets, net in our unaudited condensed consolidated statement of operations during the nine months ended December 31, 2016.

Note 16—Subsequent Events

Acquisition of Certain Assets from Murphy Energy Corporation

On January 9, 2017, the Partnership announced that it had closed its acquisition of certain assets from Murphy Energy Corporation. The Partnership acquired a natural gas liquids terminal that supports refined products blending in Port Hudson, Louisiana, and a natural gas liquids and condensate facility in Kingfisher, Oklahoma. The combined purchase price of these assets was approximately $50.0 million. A deposit of $4.1 million was paid in December 2016 related to this transaction and was recorded within noncurrent assets in our unaudited condensed consolidated balance sheet.

Note 17—Unaudited Condensed Consolidating Guarantor and Non-Guarantor Financial Information

Certain of our wholly owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the 2019 Notes, 2021 Notes and 2023 Notes (collectively, the “Guaranteed 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 Guaranteed Notes. Since NGL Energy Partners LP received the proceeds from the issuance of the Guaranteed Notes, all activity has been reflected in the NGL Energy Partners LP (Parent) column in the tables below.

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

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 Guaranteed 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

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Unaudited Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)



	December 31, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	23,811	$	—	$	3,058		$	2,058		$	—		$	28,927
Accounts receivable-trade, net of allowance for doubtful accounts	—		—		759,627			5,663			—			765,290
Accounts receivable-affiliates	—		—		20,008			—			—			20,008
Inventories	—		—		613,223			770			—			613,993
Prepaid expenses and other current assets	—		—		133,874			611			—			134,485
Total current assets	23,811		—		1,529,790			9,102			—			1,562,703
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,656,110			90,815			—			1,746,925
GOODWILL	—		—		1,441,105			21,011			—			1,462,116
INTANGIBLE ASSETS, net of accumulated amortization	—		—		1,149,863			14,886			—			1,164,749
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		187,514			—			—			187,514
NET INTERCOMPANY RECEIVABLES (PAYABLES)	1,936,935		—		(1,916,242		)	(20,693		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,721,152		—		75,451			—			(1,796,603		)	—
LOAN RECEIVABLE-AFFILIATE	—		—		2,700			—			—			2,700
OTHER NONCURRENT ASSETS	—		—		251,204			165			—			251,369
Total assets	$	3,681,898	$	—	$	4,377,495		$	115,286		$	(1,796,603	)	$	6,378,076
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	—	$	—	$	648,326		$	2,560		$	—		$	650,886
Accounts payable-affiliates	1		—		22,827			89			—			22,917
Accrued expenses and other payables	24,426		—		170,401			1,206			—			196,033
Advance payments received from customers	—		—		62,745			764			—			63,509
Current maturities of long-term debt	—		—		33,128			373			—			33,501
Total current liabilities	24,427		—		937,427			4,992			—			966,846
LONG-TERM DEBT, net of debt issuance costs and current maturities	1,678,070		—		1,537,387			1,048			—			3,216,505
OTHER NONCURRENT LIABILITIES	—		—		181,529			4,751			—			186,280
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS	61,170		—		—			—			—			61,170
EQUITY:
Partners’ equity	1,918,231		—		1,721,059			104,685			(1,825,647		)	1,918,328
Accumulated other comprehensive income (loss)	—		—		93			(190		)	—			(97		)
Noncontrolling interests	—		—		—			—			29,044			29,044
Total equity	1,918,231		—		1,721,152			104,495			(1,796,603		)	1,947,275
Total liabilities and equity	$	3,681,898	$	—	$	4,377,495		$	115,286		$	(1,796,603	)	$	6,378,076

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Unaudited Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)



	March 31, 2016
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	25,749	$	—	$	784		$	1,643		$	—		$	28,176
Accounts receivable-trade, net of allowance for doubtful accounts	—		—		516,362			4,652			—			521,014
Accounts receivable-affiliates	—		—		15,625			—			—			15,625
Inventories	—		—		367,250			556			—			367,806
Prepaid expenses and other current assets	—		—		94,426			1,433			—			95,859
Total current assets	25,749		—		994,447			8,284			—			1,028,480
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,568,488			81,084			—			1,649,572
GOODWILL	—		—		1,313,364			1,998			—			1,315,362
INTANGIBLE ASSETS, net of accumulated amortization	—		—		1,146,355			2,535			—			1,148,890
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		219,550			—			—			219,550
NET INTERCOMPANY RECEIVABLES (PAYABLES)	1,404,479		—		(1,402,360		)	(2,119		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,254,383		—		42,227			—			(1,296,610		)	—
LOAN RECEIVABLE-AFFILIATE	—		—		22,262			—			—			22,262
OTHER NONCURRENT ASSETS	—		—		175,512			527			—			176,039
Total assets	$	2,684,611	$	—	$	4,079,845		$	92,309		$	(1,296,610	)	$	5,560,155
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable-trade	$	—	$	—	$	417,707		$	2,599		$	—		$	420,306
Accounts payable-affiliates	1		—		7,190			2			—			7,193
Accrued expenses and other payables	16,887		—		196,596			943			—			214,426
Advance payments received from customers	—		—		55,737			448			—			56,185
Current maturities of long-term debt	—		—		7,109			798			—			7,907
Total current liabilities	16,888		—		684,339			4,790			—			706,017
LONG-TERM DEBT, net of debt issuance costs and current maturities	1,011,365		—		1,894,428			7,044			—			2,912,837
OTHER NONCURRENT LIABILITIES	—		—		246,695			541			—			247,236
EQUITY:
Partners’ equity	1,656,358		—		1,254,384			80,090			(1,334,317		)	1,656,515
Accumulated other comprehensive loss	—		—		(1		)	(156		)	—			(157		)
Noncontrolling interests	—		—		—			—			37,707			37,707
Total equity	1,656,358		—		1,254,383			79,934			(1,296,610		)	1,694,065
Total liabilities and equity	$	2,684,611	$	—	$	4,079,845		$	92,309		$	(1,296,610	)	$	5,560,155

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Unaudited Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)



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

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

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Unaudited Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)



	As Restated
	Three Months Ended December 31, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated

REVENUES	$	—		$	—	$	2,639,958		$	54,756		$	(9,708	)	$	2,685,006
COST OF SALES	—			—		2,436,088			7,065			(9,653		)	2,433,500
OPERATING COSTS AND EXPENSES:
Operating	—			—		82,761			22,015			(55		)	104,721
General and administrative	—			—		17,814			5,221			—			23,035
Depreciation and amortization	—			—		46,663			12,517			—			59,180
Loss (gain) on disposal or impairment of assets, net	—			—		1,484			(156		)	—			1,328
Revaluation of liabilities	—			—		(19,312		)	—			—			(19,312		)
Operating Income	—			—		74,460			8,094			—			82,554
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		412			2,446			—			2,858
Interest expense	(17,830		)	—		(16,768		)	(1,662		)	84			(36,176		)
Other income, net	—			—		2,141			104			(84		)	2,161
(Loss) Income Before Income Taxes	(17,830		)	—		60,245			8,982			—			51,397
INCOME TAX EXPENSE	—			—		(371		)	(31		)	—			(402		)
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES	61,987			—		2,113			—			(64,100		)	—
Net Income	44,157			—		61,987			8,951			(64,100		)	50,995
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(6,838		)	(6,838		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(16,239		)	(16,239		)
NET INCOME ALLOCATED TO COMMON UNITHOLDERS	$	44,157		$	—	$	61,987		$	8,951		$	(87,177	)	$	27,918

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Unaudited Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)



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

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

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Unaudited Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)



	As Restated
	Nine Months Ended December 31, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated

REVENUES	$	—		$	—	$	9,290,209		$	155,377		$	(28,916	)	$	9,416,670
COST OF SALES	—			—		8,769,526			21,087			(28,736		)	8,761,877
OPERATING COSTS AND EXPENSES:
Operating	—			—		243,084			65,037			(180		)	307,941
General and administrative	—			—		99,022			15,792			—			114,814
Depreciation and amortization	—			—		137,208			38,564			—			175,772
Loss (gain) on disposal or impairment of assets, net	—			—		3,199			(159		)	—			3,040
Revaluation of liabilities	—			—		(46,416		)	—			—			(46,416		)
Operating Income	—			—		84,586			15,056			—			99,642
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		3,284			10,724			—			14,008
Interest expense	(53,544		)	—		(39,112		)	(6,125		)	232			(98,549		)
Other income, net	—			—		2,832			341			(232		)	2,941
(Loss) Income Before Income Taxes	(53,544		)	—		51,590			19,996			—			18,042
INCOME TAX BENEFIT (EXPENSE)	—			—		1,915			(69		)	—			1,846
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES	58,747			—		5,242			—			(63,989		)	—
Net Income	5,203			—		58,747			19,927			(63,989		)	19,888
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(14,685		)	(14,685		)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(47,798		)	(47,798		)
NET INCOME ALLOCATED TO COMMON UNITHOLDERS	$	5,203		$	—	$	58,747		$	19,927		$	(126,472	)	$	(42,595	)

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Unaudited Condensed Consolidating Statements of Comprehensive Income (Loss)

(U.S. Dollars in Thousands)



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



	As Restated
	Three Months Ended December 31, 2015
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net income	$	44,157	$	—	$	61,987	$	8,951		$	(64,100	)	$	50,995
Other comprehensive loss	—		—		—		(12		)	—			(12		)
Comprehensive income	$	44,157	$	—	$	61,987	$	8,939		$	(64,100	)	$	50,983



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



	As Restated
	Nine Months Ended December 31, 2015
	NGL Energy Partners LP (Parent)		NGL Energy Finance Corp.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net income	$	5,203	$	—	$	58,747	$	19,927		$	(63,989	)	$	19,888
Other comprehensive loss	—		—		—		(39		)	—			(39		)
Comprehensive income	$	5,203	$	—	$	58,747	$	19,888		$	(63,989	)	$	19,849

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Unaudited Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)



	Nine Months Ended December 31, 2016
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash used in operating activities	$	(48,850	)	$	—	$	(65,943	)	$	(2,872	)	$	(117,665	)
INVESTING ACTIVITIES:
Capital expenditures	—			—		(257,734		)	(6,846		)	(264,580		)
Acquisitions, net of cash acquired	—			—		(116,153		)	(11,360		)	(127,513		)
Cash flows from settlements of commodity derivatives	—			—		(82,815		)	—			(82,815		)
Proceeds from sales of assets	—			—		14,136			59			14,195
Proceeds from sale of TLP common units	—			—		112,370			—			112,370
Proceeds from sale of freshwater supply company	—			—		—			22,000			22,000
Distributions of capital from unconsolidated entities	—			—		7,608			—			7,608
Payments on loan for natural gas liquids facility	—			—		6,585			—			6,585
Loan to affiliate	—			—		(2,700		)	—			(2,700		)
Payments on loan to affiliate	—			—		655			—			655
Payment to terminate development agreement	—			—		(16,875		)	—			(16,875		)
Net cash (used in) provided by investing activities	—			—		(334,923		)	3,853			(331,070		)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	—			—		1,176,000			—			1,176,000
Payments on revolving credit facilities	—			—		(1,510,500		)	—			(1,510,500		)
Issuance of senior notes	700,000			—		—			—			700,000
Repurchases of senior notes	(15,129		)	—		—			—			(15,129		)
Payments on other long-term debt	—			—		(6,359		)	(190		)	(6,549		)
Debt issuance costs	(12,536		)	—		(72		)	—			(12,608		)
Contributions from general partner	59			—		—			—			59
Contributions from noncontrolling interest owners, net	—			—		—			639			639
Distributions to partners	(132,135		)	—		—			—			(132,135		)
Distributions to noncontrolling interest owners	—			—		—			(3,292		)	(3,292		)
Proceeds from sale of convertible preferred units and warrants, net of offering costs	234,989			—		—			—			234,989
Proceeds from sale of common units, net of offering costs	43,896			—		—			—			43,896
Payments for the early extinguishment of liabilities	—			—		(25,884		)	—			(25,884		)
Net changes in advances with consolidated entities	(772,232		)	—		769,955			2,277			—
Net cash provided by financing activities	46,912			—		403,140			(566		)	449,486
Net (decrease) increase in cash and cash equivalents	(1,938		)	—		2,274			415			751
Cash and cash equivalents, beginning of period	25,749			—		784			1,643			28,176
Cash and cash equivalents, end of period	$	23,811		$	—	$	3,058		$	2,058		$	28,927

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

At December 31, 2016 and March 31, 2016, and for the

Three Months and Nine Months Ended December 31, 2016 and 2015

Unaudited Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)



	Nine Months Ended December 31, 2015
	NGL Energy Partners LP (Parent)			NGL Energy Finance Corp.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash (used in) provided by operating activities	$	(52,989	)	$	—	$	276,244		$	69,879		$	293,134
INVESTING ACTIVITIES:
Capital expenditures	—			—		(439,476		)	(57,671		)	(497,147		)
Acquisitions, net of cash acquired	(624		)	—		(184,852		)	(1,880		)	(187,356		)
Cash flows from settlements of commodity derivatives	—			—		92,216			—			92,216
Proceeds from sales of assets	—			—		4,979			2			4,981
Investments in unconsolidated entities	—			—		(3,647		)	(4,726		)	(8,373		)
Distributions of capital from unconsolidated entities	—			—		8,761			5,282			14,043
Loan for natural gas liquids facility	—			—		(3,913		)	—			(3,913		)
Payments on loan for natural gas liquids facility	—			—		5,552			—			5,552
Loan to affiliate	—			—		(15,621		)	—			(15,621		)
Payments on loan to affiliate	—			—		517			—			517
Net cash used in investing activities	(624		)	—		(535,484		)	(58,993		)	(595,101		)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	—			—		1,961,000			81,100			2,042,100
Payments on revolving credit facilities	—			—		(1,431,000		)	(83,100		)	(1,514,100		)
Proceedings from borrowings under other long-term debt	—			—		45,873			7,350			53,223
Payments on other long-term debt	—			—		(3,579		)	(70		)	(3,649		)
Debt issuance costs	(3,209		)	—		(5,226		)	(1,249		)	(9,684		)
Contributions from general partner	54			—		—			—			54
Contributions from noncontrolling interest owners, net	—			—		—			10,037			10,037
Distributions to partners	(238,414		)	—		—			—			(238,414		)
Distributions to noncontrolling interest owners	—			—		—			(26,638		)	(26,638		)
Taxes paid on behalf of equity incentive plan participants	—			—		(19,303		)	—			(19,303		)
Common unit repurchases	(7,707		)	—		—			—			(7,707		)
Net changes in advances with consolidated entities	295,204			—		(295,999		)	795			—
Other	—			—		(34		)	(42		)	(76		)
Net cash provided by (used in) financing activities	45,928			—		251,732			(11,817		)	285,843
Net decrease in cash and cash equivalents	(7,685		)	—		(7,508		)	(931		)	(16,124		)
Cash and cash equivalents, beginning of period	29,115			—		9,757			2,431			41,303
Cash and cash equivalents, end of period	$	21,430		$	—	$	2,249		$	1,500		$	25,179

Table of Contents

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

The following is a discussion of NGL Energy Partners LP’s (“we,” “us,” “our,” or the “Partnership”) financial condition and results of operations as of and for the three months and nine months ended December 31, 2016. 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 included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2016 (“Annual Report”).

Overview

We are a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At December 31, 2016, our operations include:

•

Our Crude Oil Logistics segment, the assets of which include owned and leased crude oil storage terminals and pipeline injection stations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned barges and towboats, and interests in two crude oil pipelines, purchases crude oil from producers and transports it to refineries or for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. During the three months ended December 31, 2016, the segment generated an operating loss of $9.2 million. The segment generated operating income of $0.8 million during the three months ended December 31, 2015. During the nine months ended December 31, 2016, the segment generated an operating loss of $28.8 million. The segment generated operating income of $12.7 million during the nine months ended December 31, 2015.

•

Our Water Solutions segment, the assets of which include water pipelines, water treatment and disposal facilities, washout facilities, and solid waste disposal facilities, 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 washouts. In addition, our Water Solutions segment sells the recovered hydrocarbons that result from performing these services. During the three months ended December 31, 2016, the segment generated an operating loss of $11.9 million. The segment generated operating income of $15.6 million during the three months ended December 31, 2015. During the nine months ended December 31, 2016, the segment generated operating income of $63.1 million, which includes the reversal of $124.7 million of the previously recorded $380.2 million goodwill impairment charge recorded during the three months ended March 31, 2016 (see Note 6 to our unaudited condensed consolidated financial statements included in this Quarterly Report). The segment generated operating income of $44.3 million during the nine months ended December 31, 2015.

•

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 18 owned terminals throughout the United States, and provides terminaling and storage services at its salt dome storage facility in Utah. During the three months ended December 31, 2016, the segment generated operating income of $24.8 million. The segment generated operating income of $32.9 million during the three months ended December 31, 2015. During the nine months ended December 31, 2016, the segment generated operating income of $33.1 million. The segment generated operating income of $52.8 million during the nine months ended December 31, 2015.

•

Our Retail Propane segment sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 28 states and the District of Columbia. During the three months ended December 31, 2016, the segment generated operating income of $21.8 million. The segment generated operating income of $14.5 million during the three months ended December 31, 2015. During the nine months ended December 31, 2016, the segment generated operating income of $10.6 million. The segment generated operating income of $12.0 million during the nine months ended December 31, 2015.

•

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. During the three months ended December 31, 2016, the segment generated operating income of $8.2 million. The segment generated operating income of $31.7 million during the three months ended December 31, 2015. During the nine months ended December 31, 2016, the segment generated operating income of $169.4 million, which includes a gain of $104.1 million recorded on the sale of all of the TransMontaigne Partners L.P. (“TLP”) common units we

Table of Contents

owned during the nine months ended December 31, 2016. The segment generated operating income of $59.5 million during the nine months ended December 31, 2015.

Correction of Error

As previously reported, subsequent to the issuance of certain previously issued financial statements, in the fourth quarter of fiscal year 2016, we determined that there were errors in those financial statements from not recording certain contingent consideration liabilities related to royalty agreements assumed as part of acquisitions in our Water Solutions segment. The effect of the error was material to the financial statements for each of the first three quarters of the fiscal year ended March 31, 2016, so those quarters have been restated for the effects of the error correction. We have restated our previously issued unaudited condensed consolidated statements of operations and unaudited condensed consolidated statements of comprehensive income (loss) for the three months and nine months ended December 31, 2015 and unaudited condensed consolidated statement of cash flows for the nine months ended December 31, 2015. See Note 17 to our consolidated financial statements in our Annual Report for a summary of the impact of the error correction for the three months and nine months ended December 31, 2015.

Recent Developments

Transactions during the Three Months Ended December 31, 2016

2023 Notes

On October 24, 2016, we entered into a Note Purchase Agreement (as amended, the “2023 Note Purchase Agreement”) whereby we issued $700.0 million of Senior Unsecured Notes (the “2023 Notes”) in a private placement. The 2023 Notes bear interest at 7.50%, which is payable on May 1 and November 1 of each year, beginning on May 1, 2017. We received net proceeds of $687.9 million, after the initial purchasers’ discount of $10.5 million and offering costs of $1.6 million. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further description of these notes.

Subsequent Events

We acquired certain natural gas liquid terminals and facilities for approximately $50.0 million. For a further discussion of our subsequent events, see Note 16 to our unaudited condensed consolidated financial statements included in this Quarterly Report.

Acquisitions

As discussed below, we completed numerous acquisitions during the fiscal year ended March 31, 2016 and the nine months ended December 31, 2016. These acquisitions impact the comparability of our results of operations between periods in our current and prior fiscal years.

During the nine months ended December 31, 2016, in our Water Solutions segment, we (i) acquired three water solutions facilities, (ii) acquired the remaining 25% ownership interest in three water solutions facilities, (iii) acquired an additional 24.5% interest in an existing produced water pipeline company, and (iv) acquired the remaining 65% ownership interest in a freshwater supply company. During the nine months ended December 31, 2016, 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, 2016, in our Water Solutions segment, we (i) acquired a 57.125% interest in an existing water pipeline company and (ii) acquired 20 water solutions facilities and a 50% interest in an additional facility. During the fiscal year ended March 31, 2016, in our Retail Propane segment, we acquired six retail propane businesses. See Note 4 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Table of Contents

Dispositions

Sale of Freshwater Supply Company

On November 29, 2016, we sold our freshwater supply company. We received proceeds of $22.0 million and recorded a loss on the sale of $2.3 million during the three months ended December 31, 2016. See Note 4 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Consolidated Results of Operations

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



				As Restated						As Restated
	Three Months Ended December 31,						Nine Months Ended December 31,
	2016			2015			2016			2015
	(in thousands)
Total revenues	$	3,406,641		$	2,685,006		$	9,174,149		$	9,416,670
Total cost of sales	3,228,022			2,433,500			8,723,192			8,761,877
Operating expenses	76,981			104,721			225,408			307,941
General and administrative expense	18,280			23,035			88,077			114,814
Depreciation and amortization	60,767			59,180			160,276			175,772
Loss (gain) on disposal or impairment of assets, net	34			1,328			(203,433		)	3,040
Revaluation of liabilities	—			(19,312		)	—			(46,416		)
Operating income	22,557			82,554			180,629			99,642
Equity in earnings of unconsolidated entities	1,279			2,858			1,726			14,008
Revaluation of investments	—			—			(14,365		)	—
Interest expense	(41,436		)	(36,176		)	(105,316		)	(98,549		)
Gain on early extinguishment of liabilities	—			—			30,890			—
Other income, net	20,007			2,161			25,860			2,941
Income before income taxes	2,407			51,397			119,424			18,042
Income tax (expense) benefit	(1,114		)	(402		)	(2,036		)	1,846
Net income	1,293			50,995			117,388			19,888
Less: Net income attributable to noncontrolling interests	(317		)	(6,838		)	(6,091		)	(14,685		)
Net income attributable to NGL Energy Partners LP	976			44,157			111,297			5,203
Less: Distributions to preferred unitholders	(8,906		)	—			(20,958		)	—
Less: Net income allocated to general partner	(22		)	(16,239		)	(180		)	(47,798		)
Net (loss) income allocated to common unitholders	$	(7,952	)	$	27,918		$	90,159		$	(42,595	)

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We have expanded our Water Solutions business considerably through numerous acquisitions of water treatment and disposal facilities. We have expanded our Retail Propane business through numerous acquisitions of retail propane businesses. As previously reported, on February 1, 2016, we sold our general partner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting. On April 1, 2016, we sold all of the TLP common units that we owned. The results of operations of our Liquids and Retail Propane businesses are impacted by seasonality, due primarily to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our sales volumes and revenues. For these and other reasons, our results of operations for the three months and nine months ended December 31, 2016 are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2017. See the detailed discussion of items affecting operating income (loss) by segment below.

Table of Contents

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, gain on early extinguishment of liabilities, revaluation of investments, equity-based compensation expense, acquisition expense and other. We also include in Adjusted EBITDA certain inventory valuation adjustments related to our Refined Products and Renewables segment, as discussed below. EBITDA and Adjusted EBITDA should not be considered alternatives to net income, 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.

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 gains and losses associated with derivative contracts of this segment, which are intended primarily to hedge inventory holding risk, also affect Adjusted EBITDA.

Table of Contents

The following table reconciles net income to EBITDA and Adjusted EBITDA for the periods indicated:



				As Restated						As Restated
	Three Months Ended December 31,						Nine Months Ended December 31,
	2016			2015			2016			2015
	(in thousands)
Net income	$	1,293		$	50,995		$	117,388		$	19,888
Less: Net income attributable to noncontrolling interests	(317		)	(6,838		)	(6,091		)	(14,685		)
Net income attributable to NGL Energy Partners LP	976			44,157			111,297			5,203
Interest expense	41,486			34,740			105,283			92,908
Income tax expense (benefit)	1,114			384			2,036			(1,900		)
Depreciation and amortization	64,644			55,261			171,746			162,728
EBITDA	108,220			134,542			390,362			258,939
Net unrealized gains on derivatives	(3,957		)	(1,748		)	(737		)	(4,494		)
Inventory valuation adjustment (1)	7,859			(16,524		)	40,552			2,831
Lower of cost or market adjustments	731			13,251			839			7,325
Loss (gain) on disposal or impairment of assets, net	35			1,343			(203,469		)	3,056
Gain on early extinguishment of liabilities	—			—			(30,890		)	—
Revaluation of investments	—			—			14,365			—
Equity-based compensation expense (2)	6,865			3,032			39,859			52,712
Acquisition expense (3)	378			239			1,539			871
Other (4)	472			(20,676		)	7,381			(51,166		)
Adjusted EBITDA	$	120,603		$	113,459		$	259,801		$	270,074


(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 11 to our 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 11 to our condensed consolidated financial statements only include expenses associated with equity-based awards that have been formally granted.


(3)	During the three months and nine months ended December 31, 2016 and 2015, we incurred expenses related to legal and advisory costs associated with acquisitions.

(4)

The amount for the three months ended December 31, 2016 represents non-cash operating expenses related to our Grand Mesa Pipeline project. The amount for the nine months ended December 31, 2016 represents non-cash operating expenses related to our Grand Mesa Pipeline project and also includes adjustments related to noncontrolling interests. Amounts for the three months and nine months ended December 31, 2015 represent the non-cash valuation adjustment of contingent consideration liabilities, offset by the cash payments, related to royalty agreements acquired as part of acquisitions in our Water Solutions segment.

Table of Contents

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



	Three Months Ended December 31,						Nine Months Ended December 31,
	2016			2015			2016			2015
	(in thousands)
Reconciliation to unaudited condensed consolidated statements of operations:
Depreciation and amortization per EBITDA table	$	64,644		$	55,261		$	171,746		$	162,728
Intangible asset amortization recorded to cost of sales	(1,753		)	(1,701		)	(5,098		)	(5,102		)
Depreciation and amortization of unconsolidated entities	(3,048		)	(3,453		)	(9,116		)	(10,383		)
Depreciation and amortization attributable to noncontrolling interests	924			9,073			2,744			28,529
Depreciation and amortization per unaudited condensed consolidated statements of operations	$	60,767		$	59,180		$	160,276		$	175,772



	Nine Months Ended December 31,
	2016			2015
	(in thousands)
Reconciliation to unaudited condensed consolidated statements of cash flows:
Depreciation and amortization per EBITDA table	$	171,746		$	162,728
Amortization of debt issuance costs recorded to interest expense	8,192			10,207
Depreciation and amortization of unconsolidated entities	(9,116		)	(10,383		)
Depreciation and amortization attributable to noncontrolling interests	2,744			28,529
Depreciation and amortization per unaudited condensed consolidated statements of cash flows	$	173,566		$	191,081

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



	Three Months Ended December 31,					Nine Months Ended December 31,
	2016			2015		2016		2015
	(in thousands)
Interest expense per EBITDA table	$	41,486		$	34,740	$	105,283	$	92,908
Interest expense attributable to noncontrolling interests	9			1,195		17		4,590
Interest expense attributable to unconsolidated entities	(59		)	241		16		358
Gain on extinguishment of debt of unconsolidated entities	—			—		—		693
Interest expense per unaudited condensed consolidated statements of operations	$	41,436		$	36,176	$	105,316	$	98,549

Table of Contents

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 December 31, 2016
	Crude Oil Logistics			Water Solutions			Liquids			Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating (loss) income	$	(9,163	)	$	(11,898	)	$	24,765		$	21,772		$	8,209		$	(11,128	)	$	22,557
Depreciation and amortization	16,503			27,150			4,441			11,379			404			890			60,767
Amortization recorded to cost of sales	100			—			195			—			1,458			—			1,753
Net unrealized losses (gains) on derivatives	732			(1,304		)	(3,387		)	2			—			—			(3,957		)
Inventory valuation adjustment	—			—			—			—			7,859			—			7,859
Lower of cost or market adjustments	—			—			—			—			731			—			731
Loss (gain) on disposal or impairment of assets, net	4,655			2,323			60			(62		)	(6,941		)	(1		)	34
Equity-based compensation expense	—			—			—			—			—			6,865			6,865
Acquisition expense	—			—			—			(2		)	—			380			378
Other income, net	721			1,214			4			19			16,220			1,829			20,007
Adjusted EBITDA attributable to unconsolidated entities	2,577			54			—			(111		)	1,867			—			4,387
Adjusted EBITDA attributable to noncontrolling interest	—			(667		)	—			(583		)	—			—			(1,250		)
Other	472			—			—			—			—			—			472
Adjusted EBITDA	$	16,597		$	16,872		$	26,078		$	32,414		$	29,807		$	(1,165	)	$	120,603



	As Restated
	Three Months Ended December 31, 2015
	Crude Oil Logistics			Water Solutions			Liquids			Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating income (loss)	$	804		$	15,596		$	32,921		$	14,450		$	31,702		$	(12,919	)	$	82,554
Depreciation and amortization	10,041			23,644			3,537			9,096			11,493			1,369			59,180
Amortization recorded to cost of sales	62			—			261			—			1,378			—			1,701
Net unrealized (gains) losses on derivatives	(3,928		)	3,732			(1,423		)	(129		)	—			—			(1,748		)
Inventory valuation adjustment	—			—			—			—			(16,524		)	—			(16,524		)
Lower of cost or market adjustments	—			—			—			—			13,251			—			13,251
Loss (gain) on disposal or impairment of assets, net	1,115			213			5			(4		)	(1		)	—			1,328
Equity-based compensation expense	—			—			—			—			277			2,973			3,250
Acquisition expense	—			—			—			—			—			239			239
Other (expense) income, net	(672		)	569			72			113			61			2,018			2,161
Adjusted EBITDA attributable to unconsolidated entities	3,102			(352		)	—			(202		)	3,547			—			6,095
Adjusted EBITDA attributable to noncontrolling interest	—			(459		)	—			(305		)	(15,890		)	—			(16,654		)
Other	—			(21,374		)	—			—			—			—			(21,374		)
Adjusted EBITDA	$	10,524		$	21,569		$	35,373		$	23,019		$	29,294		$	(6,320	)	$	113,459

Table of Contents



	Nine Months Ended December 31, 2016
	Crude Oil Logistics			Water Solutions			Liquids		Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating (loss) income	$	(28,827	)	$	63,136		$	33,092	$	10,553		$	169,365		$	(66,690	)	$	180,629
Depreciation and amortization	34,496			76,713			13,315		31,771			1,237			2,744			160,276
Amortization recorded to cost of sales	284			—			585		—			4,229			—			5,098
Net unrealized losses (gains) on derivatives	951			(2,138		)	239		211			—			—			(737		)
Inventory valuation adjustment	—			—			—		—			40,552			—			40,552
Lower of cost or market adjustments	—			—			—		—			839			—			839
Loss (gain) on disposal or impairment of assets, net	14,617			(91,958		)	109		(96		)	(126,101		)	(4		)	(203,433		)
Equity-based compensation expense	—			—			—		—			—			39,859			39,859
Acquisition expense	—			—			—		—			—			1,539			1,539
Other (expense) income, net	(589		)	1,524			67		339			19,099			5,420			25,860
Adjusted EBITDA attributable to unconsolidated entities	7,651			(9		)	—		(388		)	3,543			—			10,797
Adjusted EBITDA attributable to noncontrolling interest	—			(2,298		)	—		(442		)	—			—			(2,740		)
Other	1,262			—			—		—			—			—			1,262
Adjusted EBITDA	$	29,845		$	44,970		$	47,407	$	41,948		$	112,763		$	(17,132	)	$	259,801



	As Restated
	Nine Months Ended December 31, 2015
	Crude Oil Logistics			Water Solutions			Liquids			Retail Propane			Refined Products and Renewables			Corporate and Other			Consolidated
	(in thousands)
Operating income (loss)	$	12,689		$	44,300		$	52,820		$	11,985		$	59,478		$	(81,630	)	$	99,642
Depreciation and amortization	30,096			66,906			11,286			26,711			36,820			3,953			175,772
Amortization recorded to cost of sales	187			—			783			—			4,132			—			5,102
Net unrealized (gains) losses on derivatives	(3,214		)	1,274			(2,163		)	(391		)	—			—			(4,494		)
Inventory valuation adjustment	—			—			—			—			2,831			—			2,831
Lower of cost or market adjustments	(1,211		)	—			—			—			8,536			—			7,325
Loss (gain) on disposal or impairment of assets, net	2,115			923			(185		)	108			79			—			3,040
Equity-based compensation expense	—			—			—			—			862			52,529			53,391
Acquisition expense	—			—			—			7			—			864			871
Other (expense) income, net	(6,432		)	1,352			279			614			444			6,684			2,941
Adjusted EBITDA attributable to unconsolidated entities	10,394			(611		)	—			(387		)	13,983			—			23,379
Adjusted EBITDA attributable to noncontrolling interest	—			(1,392		)	—			(279		)	(45,110		)	—			(46,781		)
Other	—			(52,945		)	—			—			—			—			(52,945		)
Adjusted EBITDA	$	44,624		$	59,807		$	62,820		$	38,368		$	82,055		$	(17,600	)	$	270,074

Table of Contents

Segment Operating Results for the Three Months Ended December 31, 2016 and 2015

Crude Oil Logistics

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



	Three Months Ended December 31,
	2016			2015		Change
	(in thousands, except per barrel amounts)
Revenues:
Crude oil sales	$	366,569		$	508,863	$	(142,294	)
Crude oil transportation and other	20,914			12,423		8,491
Total revenues (1)	387,483			521,286		(133,803		)
Expenses:
Cost of sales	363,416			497,390		(133,974		)
Operating expenses	10,591			9,821		770
General and administrative expenses	1,481			2,115		(634		)
Depreciation and amortization expense	16,503			10,041		6,462
Loss on disposal or impairment of assets, net	4,655			1,115		3,540
Total expenses	396,646			520,482		(123,836		)
Segment operating (loss) income	$	(9,163	)	$	804	$	(9,967	)

Crude oil sold (barrels)	7,527			10,824		(3,297		)
Crude oil sold ($/barrel)	$	48.701		$	47.012	$	1.689
Cost per crude oil sold ($/barrel)	$	48.282		$	45.953	$	2.329
Crude oil product margin ($/barrel)	$	0.419		$	1.059	$	(0.640	)


(1)	Revenues include $1.6 million and $1.9 million of intersegment sales during the three months ended December 31, 2016 and 2015, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.

Crude Oil Sales. The increase in revenue per barrel was due primarily to an increase in crude oil prices during the three months ended December 31, 2016, compared to the three months ended December 31, 2015. The decrease in our sales volumes was due primarily to increased competition due to the continued crude oil production decline.

Crude Oil Transportation and Other Revenues. The increase was due primarily to our Grand Mesa Pipeline project becoming operational on November 1, 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 December 31, 2016, compared to the three months ended December 31, 2015, and lower revenues in our trucking and barge operations during the three months ended December 31, 2016 due to a general slowdown in demand for transportation services, compared to the three months ended December 31, 2015.

Cost of Sales. Our cost of sales during the three months ended December 31, 2016 was increased by $3.4 million of net realized losses on derivatives and $0.7 million of net unrealized losses on derivatives. Our cost of sales during the three months ended December 31, 2015 was reduced by $4.0 million of net realized gains on derivatives and $3.9 million of net unrealized gains on derivatives. During the three months ended December 31, 2016, our cost of sales also decreased due to the decrease in volumes due to increased competition.

Operating and General and Administrative Expenses. The increase was due primarily to our Grand Mesa Pipeline project becoming operational on November 1, 2016, partially offset by lower compensation expense related to a reduction in the number of employees as a result of organizational changes and lower repair and maintenance expense related to trucking operations resulting from a general slowdown in demand for transportation services.

Depreciation and Amortization Expense. The increase was due primarily to our Grand Mesa Pipeline project becoming operational on November 1, 2016, partially offset by certain intangible assets being fully amortized during the fiscal year ended March 31, 2016.

Table of Contents

Loss on Disposal or Impairment of Assets, Net. During the three months ended December 31, 2016 and 2015, we recorded losses of $4.7 million and $1.1 million, respectively, on the sales of certain assets.

Water Solutions

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



				As Restated
	Three Months Ended December 31,
	2016			2015			Change
	(in thousands, except per barrel amounts)
Revenues:
Service fees	$	28,268		$	35,138		$	(6,870	)
Recovered hydrocarbons	6,387			8,414			(2,027		)
Other revenues	5,704			1,886			3,818
Total revenues	40,359			45,438			(5,079		)
Expenses:
Cost of sales-derivative gain	(238		)	(2,887		)	2,649
Cost of sales-other	715			(241		)	956
Operating expenses	21,728			27,734			(6,006		)
General and administrative expenses	579			691			(112		)
Depreciation and amortization expense	27,150			23,644			3,506
Loss on disposal or impairment of assets, net	2,323			213			2,110
Revaluation of liabilities	—			(19,312		)	19,312
Total expenses	52,257			29,842			22,415
Segment operating (loss) income	$	(11,898	)	$	15,596		$	(27,494	)

Water received (barrels)	47,489			55,648			(8,159		)
Service fees for water processed ($/barrel)	$	0.60		$	0.63		$	(0.03	)
Recovered hydrocarbons for water processed ($/barrel)	$	0.13		$	0.15		$	(0.02	)
Operating expenses for water processed ($/barrel)	$	0.46		$	0.50		$	(0.04	)

The following tables summarize activity separated between the following categories:


•	facilities we owned before September 30, 2015, which we refer to below as “existing facilities”; and


•	facilities we acquired or developed after September 30, 2015, which we refer to below as “recently acquired or developed facilities”.

Service Fee Revenues. The following table summarizes our service fee revenues (in thousands, except per barrel amounts) for the periods indicated:



	Three Months Ended December 31,
	2016					2015
	Service Fees		Water Barrels Processed	Fees Per Water Barrel Processed		Service Fees		Water Barrels Processed	Fees Per Water Barrel Processed
Existing facilities	$	19,881	30,156	$	0.66	$	27,383	41,526	$	0.66
Recently acquired or developed facilities	8,387		17,333	$	0.48	7,755		14,122	$	0.55
Total	$	28,268	47,489	$	0.60	$	35,138	55,648	$	0.63

The decrease in the volume processed at our existing facilities was due primarily to a slowdown in customer production and development activity, as well as migration of volumes from existing facilities to recently developed or acquired facilities due to the location of the new facilities.

Table of Contents

Recovered Hydrocarbon Revenues. The following table summarizes our recovered hydrocarbon revenues (in thousands, except per barrel amounts) for the periods indicated:



	Three Months Ended December 31,
	2016					2015
	Recovered Hydrocarbon Revenue		Water Barrels Processed	Revenue Per Water Barrel Processed		Recovered Hydrocarbon Revenue		Water Barrels Processed	Revenue Per Water Barrel Processed
Existing facilities	$	4,556	30,156	$	0.15	$	7,120	41,526	$	0.17
Recently acquired or developed facilities	1,831		17,333	$	0.11	1,294		14,122	$	0.09
Total	$	6,387	47,489	$	0.13	$	8,414	55,648	$	0.15

The decrease in revenue per barrel associated with recovered hydrocarbons was due primarily to a decrease in the amount of hydrocarbons per barrel of water processed.

Other Revenues. Other revenues primarily include solids disposal revenues, freshwater revenues, and water pipeline revenues. The increase was due primarily to an increase in revenues in the freshwater and water pipeline businesses as well as revenue from trucking wastewater to our water solutions facilities. See the below discussion of the loss on the sale of our freshwater supply company.

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. Our cost of sales during the three months ended December 31, 2016 included $1.3 million of net unrealized gains on derivatives and $1.1 million of net realized losses on derivatives. Our cost of sales during the three months ended December 31, 2015 included $6.6 million of net realized gains on derivatives and $3.7 million of net unrealized losses on derivatives.

Cost of Sales-Other. The increase was due to trucking expenses to bring wastewater to our water solutions facilities.

Operating Expenses. The following table summarizes our operating expenses (in thousands, except per barrel amounts) for the periods indicated:



						As Restated
	Three Months Ended December 31,
	2016					2015
	Operating Expenses		Water Barrels Processed	Operating Expenses Per Water Barrel Processed		Operating Expenses		Water Barrels Processed	Operating Expenses Per Water Barrel Processed
Existing facilities	$	15,954	30,156	$	0.53	$	22,281	41,526	$	0.54
Recently acquired or developed facilities	5,774		17,333	$	0.33	5,453		14,122	$	0.39
Total	$	21,728	47,489	$	0.46	$	27,734	55,648	$	0.50

The decrease in operating expenses per barrel was due primarily to lower operating costs of water disposal wells due to lower volumes processed and cost reduction efforts.

Depreciation and Amortization Expense. Of the increase, $4.4 million related to recently acquired or developed water treatment and disposal facilities and $0.3 million related to recently developed solids processing facilities. The increase was partially offset by certain intangible assets being fully amortized during the three months ended December 31, 2015 and lower amortization expense during the three months ended December 31, 2016 from the write-off of the development agreement asset in June 2016 (see Note 15 to our unaudited condensed consolidated financial statements included in this Quarterly Report).

Loss on Disposal or Impairment of Assets, Net. During the three months ended December 31, 2016, we recorded a loss of $2.3 million on the sale of our freshwater supply company (see Note 4 to our unaudited condensed consolidated financial statements included in this Quarterly Report). During the three months ended December 31, 2015, we recorded a loss of $0.2 million on the sale and disposal of certain assets.

Table of Contents

Revaluation of Liabilities. The revaluation of liabilities represents the valuation adjustment of contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations during the three months ended December 31, 2015. During the three months ended December 31, 2016, we did not identify any significant changes in our Water Solutions operations, which would require a revaluation of the contingent consideration obligation, and as such, no adjustment was recorded.

Liquids

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



	Three Months Ended December 31,
	2016		2015		Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	260,562	$	188,930	$	71,632
Cost of sales	242,949		170,558		72,391
Product margin	17,613		18,372		(759		)

Other product sales:
Revenues (1)	235,739		180,620		55,119
Cost of sales	219,317		150,203		69,114
Product margin	16,422		30,417		(13,995		)

Other revenues:
Revenues (1)	7,704		8,161		(457		)
Cost of sales	2,410		4,189		(1,779		)
Product margin	5,294		3,972		1,322

Expenses:
Operating expenses	8,846		14,616		(5,770		)
General and administrative expenses	1,217		1,681		(464		)
Depreciation and amortization expense	4,441		3,537		904
Loss on disposal or impairment of assets, net	60		6		54
Total expenses	14,564		19,840		(5,276		)
Segment operating income	$	24,765	$	32,921	$	(8,156	)

Propane sold (gallons)	386,854		348,511		38,343
Propane sold ($/gallon)	$	0.674	$	0.542	$	0.132
Cost per propane sold ($/gallon)	$	0.628	$	0.489	$	0.139
Propane product margin ($/gallon)	$	0.046	$	0.053	$	(0.007	)

Other products sold (gallons)	239,377		225,695		13,682
Other products sold ($/gallon)	$	0.985	$	0.800	$	0.185
Cost per other products sold ($/gallon)	$	0.916	$	0.666	$	0.250
Other products product margin ($/gallon)	$	0.069	$	0.134	$	(0.065	)


(1)	Revenues include $33.7 million and $24.2 million of intersegment sales during the three months ended December 31, 2016 and 2015, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.

Propane Sales. Propane margins are lower due to market values falling below weighted cost of inventory for a portion of the quarter.

Our cost of wholesale propane sales was reduced by $0.7 million of net unrealized gains on derivatives and reduced

Table of Contents

by less than $0.1 million of net realized gains on derivatives during the three months ended December 31, 2016. During the three months ended December 31, 2015, our cost of wholesale propane sales was reduced by $1.7 million of net unrealized gains on derivatives and increased by $4.0 million of net realized losses on derivatives. The increase in cost per gallon of propane was due to higher commodity prices.

Other Products Sales. The increase in the volume of other products sold was primarily due to increases in production related to a customer’s contract.

Our cost of sales of other products was reduced by $2.7 million of net unrealized gains on derivatives and increased by $6.0 million of net realized losses on derivatives during the three months ended December 31, 2016. Our cost of sales of other products during the three months ended December 31, 2015 was increased by $0.2 million of net unrealized losses on derivatives and reduced by $1.8 million of net realized gains on derivatives.

Product margins during the three months ended December 31, 2015 benefited from a high level of butane supply in the market, which lowered our product cost.

Other Revenues. This revenue includes storage, terminaling and transportation services income. Other revenue margins increased primarily due to a decrease of costs incurred related to the transportation services agreements.

Operating and General and Administrative Expenses. The decrease was due primarily to a decrease in incentive compensation and commission expense associated with lower product sales.

Depreciation and Amortization Expense. The increase was due primarily to purchase accounting adjustments for the Sawtooth cavern acquisition during the three months ended December 31, 2015.

Table of Contents

Retail Propane

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



	Three Months Ended December 31,
	2016			2015			Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues	$	96,699		$	68,880		$	27,819
Cost of sales	42,463			27,471			14,992
Product margin	54,236			41,409			12,827

Distillate sales:
Revenues	19,569			19,133			436
Cost of sales	14,300			14,198			102
Product margin	5,269			4,935			334

Other revenues:
Revenues	12,418			12,132			286
Cost of sales	3,745			4,305			(560		)
Product margin	8,673			7,827			846

Expenses:
Operating expenses	32,279			27,650			4,629
General and administrative expenses	2,810			2,980			(170		)
Depreciation and amortization expense	11,379			9,096			2,283
Gain on disposal or impairment of assets, net	(62		)	(5		)	(57		)
Total expenses	46,406			39,721			6,685
Segment operating income	$	21,772		$	14,450		$	7,322

Propane sold (gallons)	56,572			42,436			14,136
Propane sold ($/gallon)	$	1.709		$	1.623		$	0.086
Cost per propane sold ($/gallon)	$	0.751		$	0.647		$	0.104
Propane product margin ($/gallon)	$	0.958		$	0.976		$	(0.018	)

Distillates sold (gallons)	9,139			9,102			37
Distillates sold ($/gallon)	$	2.141		$	2.102		$	0.039
Cost per distillates sold ($/gallon)	$	1.565		$	1.560		$	0.005
Distillates product margin ($/gallon)	$	0.576		$	0.542		$	0.034

Revenues. Propane revenues and volumes increased due to three acquisitions in the current year and slightly colder weather in the current winter. Distillates revenues and volumes increased due to slightly colder weather in the current winter.

Cost of Sales. The increase in propane cost is due to the current year acquisitions of three companies as well as an increase in commodity prices. The distillates cost increase was due to an increase in commodity prices.

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

Depreciation and Amortization Expense. The increase was due primarily to acquisitions of retail propane businesses.

Table of Contents

Refined Products and Renewables

The following table summarizes the operating results of our Refined Products and Renewables segment for the periods indicated. As previously reported, on February 1, 2016, we sold our general partner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting. Also, on April 1, 2016, we sold all of the TLP common units we owned.



	Three Months Ended December 31,
	2016			2015			Change
	(in thousands, except per barrel and per gallon amounts)
Refined products sales:
Revenues (1)	$	2,258,317		$	1,532,928		$	725,389
Cost of sales	2,254,283			1,503,358			750,925
Product margin	4,034			29,570			(25,536		)

Renewables sales:
Revenues	123,065			101,414			21,651
Cost of sales	120,041			91,253			28,788
Product margin	3,024			10,161			(7,137		)

Service fee revenues	50			32,381			(32,331		)

Expenses:
Operating expenses	3,198			24,888			(21,690		)
General and administrative expenses	2,238			4,030			(1,792		)
Depreciation and amortization expense	404			11,493			(11,089		)
Gain on disposal or impairment of assets, net	(6,941		)	(1		)	(6,940		)
Total (income) expense, net	(1,101		)	40,410			(41,511		)
Segment operating income	$	8,209		$	31,702		$	(23,493	)

Refined products sold (barrels)	35,442			26,134			9,308
Refined products sold ($/barrel)	$	63.719		$	58.656		$	5.063
Cost per refined products sold ($/barrel)	$	63.605		$	57.525		$	6.080
Refined products product margin ($/barrel)	$	0.114		$	1.131		$	(1.017	)
Refined products product margin ($/gallon)	$	0.003		$	0.027		$	(0.024	)

Renewable products sold (barrels)	1,858			1,461			397
Renewable products sold ($/barrel)	$	66.235		$	69.414		$	(3.179	)
Cost per renewable products sold ($/barrel)	$	64.608		$	62.459		$	2.149
Renewable products product margin ($/barrel)	$	1.627		$	6.955		$	(5.328	)
Renewable products product margin ($/gallon)	$	0.039		$	0.166		$	(0.127	)


(1)	Revenues include $0.1 million and $0.2 million of intersegment sales during the three months ended December 31, 2016 and 2015, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.

Refined Products Sales and Cost of Sales. The increase in revenues and cost of sales was due to increased volumes and an increase in refined products prices. The increased volumes were due primarily to an increase in pipeline capacity rights purchased during the fiscal year ended March 31, 2016 and nine months ended December 31, 2016, an expansion of our refined products operations, and the continued demand for motor fuels in the current low gasoline price environment. Product margins during the three months ended December 31, 2016 were negatively impacted by losses on our derivative and risk management contracts due to NYMEX prices increasing during the three months ended December 31, 2016. Our inventories are carried at the lower of cost or market while our derivative and risk management contracts are carried at fair value. As a result, if refined product prices are increasing during the quarter, we report losses on derivative and risk management contracts in our unaudited

Table of Contents

condensed consolidated statement of operations and any gains on inventory would not be realized until the inventory is sold the following quarter. Product margin during the three months ended December 31, 2016 was also impacted by storage fees paid to TLP which are no longer eliminated as TLP was deconsolidated on February 1, 2016.

Renewables Sales. The increase in revenues was due to increased volumes, partially offset by a decrease in renewables prices. Per-barrel product margins were lower during the three months ended December 31, 2016, compared to the three months ended December 31, 2015 as a result of the biodiesel tax credit being in place for the entire 2016 calendar year, compared to being reinstated in December 2015 for the 2015 calendar year.

Service Fee Revenues, Operating Expenses, General and Administrative Expenses, Depreciation and Amortization Expense. The decrease in each of these line items was due primarily to the inclusion of TLP for the three months ended December 31, 2015 with no comparable activity in the current period, as TLP was deconsolidated on February 1, 2016.

Gain on Disposal or Impairment of Assets, Net. During the three months ended December 31, 2016, we recognized $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 December 31, 2016, we recorded a loss of $0.6 million on the sales of certain assets. During the three months ended December 31, 2015, we recorded 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 December 31,
	2016			2015			Change
	(in thousands)
Other revenues:
Revenues	$	164		$	—		$	164
Cost of sales	77			—			77
Margin	87			—			87

Expenses:
Operating expenses	371			12			359
General and administrative expenses	9,955			11,538			(1,583		)
Depreciation and amortization expense	890			1,369			(479		)
Gain on disposal or impairment of assets, net	(1		)	—			(1		)
Total expenses	11,215			12,919			(1,704		)
Operating loss	$	(11,128	)	$	(12,919	)	$	1,791

General and Administrative Expenses. The decrease during the three months ended December 31, 2016 was due primarily to lower compensation expense and the reversal of certain accruals that were ultimately covered by insurance.

Equity in Earnings of Unconsolidated Entities

The decrease of $1.6 million during the three months ended December 31, 2016 was due primarily to a decrease of $2.4 million of earnings from TLP (including Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and Frontera Brownsville LLC (“Frontera”)) that we acquired as part of our July 2014 acquisition of TransMontaigne Inc. (“TransMontaigne”). On February 1, 2016, we deconsolidated TLP when we sold our general partner interest in TLP, and on April 1, 2016, we sold all of the TLP common units we owned. This decrease was partially offset by an increase of $0.6 million in earnings from our investments in Glass Mountain Pipeline, LLC (“Glass Mountain”) and an ethanol production facility.

Interest Expense

Interest expense includes interest expense on our revolving credit facilities 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 $5.3 million during the three months ended December 31, 2016 was due primarily to the issuance

Table of Contents

of $700.0 million of fixed-rate notes during October 2016, partially offset by lower interest expense related to TLP’s credit facility (our interest in TLP was acquired in July 2014, and we deconsolidated TLP as of February 1, 2016) and lower interest expense as we repurchased a portion of the 2019 Notes (as defined herein) and 2021 Notes (as defined herein) during the three months ended March 31, 2016 and the three months ended June 30, 2016.

Other Income, Net

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



	Three Months Ended December 31,
	2016		2015
	(in thousands)
Interest income (1)	$	1,921	$	2,722
Crude oil marketing arrangement (2)	39		(551		)
Termination of storage sublease agreement (3)	16,205		—
Other (4)	1,842		(10		)
Other income, net	$	20,007	$	2,161

(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 loan receivables from equity method investees. On June 3, 2016, we acquired the remaining 65% ownership interest in an equity method investee 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)


(4)	Relates primarily to a gain on insurance settlement from damage to two facilities in our Water Solutions segment and a payment received related to a contract termination.

Income Tax Expense (Benefit)

Income tax expense was $1.1 million during the three months ended December 31, 2016, compared to income tax expense of $0.4 million during the three months ended December 31, 2015. See Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Noncontrolling Interests

The decrease of $6.5 million during the three months ended December 31, 2016 was due primarily to the deconsolidation of TLP on February 1, 2016 as a result of the sale of our general partner interest in TLP.

Table of Contents

Segment Operating Results for the Nine Months Ended December 31, 2016 and 2015

Crude Oil Logistics

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



	Nine Months Ended December 31,
	2016			2015		Change
	(in thousands, except per barrel amounts)
Revenues:
Crude oil sales	$	1,123,169		$	2,818,752	$	(1,695,583	)
Crude oil transportation and other	43,020			44,118		(1,098		)
Total revenues (1)	1,166,189			2,862,870		(1,696,681		)
Expenses:
Cost of sales	1,112,034			2,778,323		(1,666,289		)
Operating expenses	29,413			33,422		(4,009		)
General and administrative expenses	4,456			6,225		(1,769		)
Depreciation and amortization expense	34,496			30,096		4,400
Loss on disposal or impairment of assets, net	14,617			2,115		12,502
Total expenses	1,195,016			2,850,181		(1,655,165		)
Segment operating (loss) income	$	(28,827	)	$	12,689	$	(41,516	)

Crude oil sold (barrels)	24,838			55,911		(31,073		)
Crude oil sold ($/barrel)	$	45.220		$	50.415	$	(5.195	)
Cost per crude oil sold ($/barrel)	$	44.771		$	49.692	$	(4.921	)
Crude oil product margin ($/barrel)	$	0.449		$	0.723	$	(0.274	)


(1)	Revenues include $4.4 million and $8.1 million of intersegment sales during the nine months ended December 31, 2016 and 2015, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.

Crude Oil Sales. The decrease in revenue per barrel was due primarily to the decline in crude oil prices during the nine months ended December 31, 2016, compared to the nine months ended December 31, 2015. The decrease in our sales volumes was due primarily to increased competition due to the continued crude oil production decline. In addition, we also had an increase in buy/sell transactions during the nine months ended December 31, 2016, compared to the nine months ended December 31, 2015. These are transactions in which we transact to purchase product from a counterparty and sell the same volumes of product to the same counterparty at a different location or time. As the revenues and costs of sales are netted for these transaction, so are the volumes.

Crude Oil Transportation and Other Revenues. The decrease was due primarily to the flattening of the contango curve for crude oil (a condition in which forward crude oil prices are greater than spot prices) during the nine months ended December 31, 2016, compared to the nine months ended December 31, 2015, and lower revenues in our trucking and barge operations during the nine months ended December 31, 2016 due to a general slowdown in demand for transportation services, compared to the nine months ended December 31, 2015, partially offset by our Grand Mesa Pipeline project becoming operational on November 1, 2016.

Cost of Sales. Our cost of sales during the nine months ended December 31, 2016 was increased by $8.9 million of net realized losses on derivatives and $1.0 million of net unrealized losses on derivatives. Our cost of sales during the nine months ended December 31, 2015 was reduced by $6.1 million of net realized gains on derivatives and $3.2 million of net unrealized gains on derivatives. During the nine months ended December 31, 2016, our cost of sales also decreased due to the decline in crude oil prices and the decrease in volumes due to increased competition.

Operating and General and Administrative Expenses. The decrease was due primarily to lower compensation expense related to a reduction in the number of employees as a result of organizational changes, lower repair and maintenance expense related to trucking operations resulting from a general slowdown in demand for transportation services, and lower repair and

Table of Contents

maintenance expense related to having a newer fleet of barges and the timing of repairs, partially offset by our Grand Mesa Pipeline project becoming operational on November 1, 2016.

Loss on Disposal or Impairment of Assets, Net. During the nine months ended December 31, 2016, we recorded a loss of $10.9 million on the sales of certain assets and a loss of $3.7 million due to the write-down of certain other assets. During the nine months ended December 31, 2015, we recorded a loss of $2.1 million on the sales of certain assets.

Water Solutions

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



				As Restated
	Nine Months Ended December 31,
	2016			2015			Change
	(in thousands, except per barrel amounts)
Revenues:
Service fees	$	82,493		$	107,079		$	(24,586	)
Recovered hydrocarbons	19,264			34,978			(15,714		)
Other revenues	14,088			5,168			8,920
Total revenues	115,845			147,225			(31,380		)
Expenses:
Cost of sales-derivative loss (gain)	2,449			(7,847		)	10,296
Cost of sales-other	1,422			(241		)	1,663
Operating expenses	62,233			87,506			(25,273		)
General and administrative expenses	1,850			2,094			(244		)
Depreciation and amortization expense	76,713			66,906			9,807
(Gain) loss on disposal or impairment of assets, net	(91,958		)	923			(92,881		)
Revaluation of liabilities	—			(46,416		)	46,416
Total expenses	52,709			102,925			(50,216		)
Segment operating income	$	63,136		$	44,300		$	18,836

Water received (barrels)	134,913			164,843			(29,930		)
Service fees for water processed ($/barrel)	$	0.61		$	0.65		$	(0.04	)
Recovered hydrocarbons for water processed ($/barrel)	$	0.14		$	0.21		$	(0.07	)
Operating expenses for water processed ($/barrel)	$	0.46		$	0.53		$	(0.07	)

The following tables summarize activity separated between the following categories:


•	facilities we owned before March 31, 2015, which we refer to below as “existing facilities”; and


•	facilities we acquired or developed after March 31, 2015, which we refer to below as “recently acquired or developed facilities”.

Table of Contents

Service Fee Revenues. The following table summarizes our service fee revenues (in thousands, except per barrel amounts) for the periods indicated:



	Nine Months Ended December 31,
	2016					2015
	Service Fees		Water Barrels Processed	Fees Per Water Barrel Processed		Service Fees		Water Barrels Processed	Fees Per Water Barrel Processed
Existing facilities	$	58,984	88,458	$	0.67	$	90,868	137,239	$	0.66
Recently acquired or developed facilities	23,509		46,455	$	0.51	16,211		27,604	$	0.59
Total	$	82,493	134,913	$	0.61	$	107,079	164,843	$	0.65

Recovered Hydrocarbon Revenues. The following table summarizes our recovered hydrocarbon revenues (in thousands, except per barrel amounts) for the periods indicated:



	Nine Months Ended December 31,
	2016					2015
	Recovered Hydrocarbon Revenue		Water Barrels Processed	Revenue Per Water Barrel Processed		Recovered Hydrocarbon Revenue		Water Barrels Processed	Revenue Per Water Barrel Processed
Existing facilities	$	13,973	88,458	$	0.16	$	31,838	137,239	$	0.23
Recently acquired or developed facilities	5,291		46,455	$	0.11	3,140		27,604	$	0.11
Total	$	19,264	134,913	$	0.14	$	34,978	164,843	$	0.21

The decrease in revenue per barrel associated with recovered hydrocarbons was due primarily to a decrease in the amount of hydrocarbons per barrel of water processed.

Other Revenues. The increase was due primarily to an increase in revenues in the freshwater and water pipeline businesses as well as revenue from trucking wastewater to our water solutions facilities. See the below discussion of the loss on the sale of our freshwater supply company.

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. Our cost of sales during the nine months ended December 31, 2016 included $4.6 million of net realized losses on derivatives and $2.1 million of net unrealized gains on derivatives. Our cost of sales during the nine months ended December 31, 2015 included $9.1 million of net realized gains on derivatives and $1.3 million of net unrealized losses on derivatives.

Cost of Sales-Other. The increase was due to trucking expenses to bring wastewater to our water solutions facilities.

Operating Expenses. The following table summarizes our operating expenses (in thousands, except per barrel amounts) for the periods indicated:



						As Restated
	Nine Months Ended December 31,
	2016					2015
	Operating Expenses		Water Barrels Processed	Operating Expenses Per Water Barrel Processed		Operating Expenses		Water Barrels Processed	Operating Expenses Per Water Barrel Processed
Existing facilities	$	46,562	88,458	$	0.53	$	76,772	137,239	$	0.56
Recently acquired or developed facilities	15,671		46,455	$	0.34	10,734		27,604	$	0.39
Total	$	62,233	134,913	$	0.46	$	87,506	164,843	$	0.53

Table of Contents

The decrease in operating expenses per barrel was due primarily to lower operating costs of water disposal wells due to lower volumes processed and cost reduction efforts.

Depreciation and Amortization Expense. Of the increase, $9.9 million related to recently acquired or developed water treatment and disposal facilities and $1.6 million related to recently developed solids processing facilities. The increase was partially offset by certain intangible assets being fully amortized during the nine months ended December 31, 2015 and lower amortization expense during the nine months ended December 31, 2016 from the write-off of the development agreement asset in June 2016 (see Note 15 to our unaudited condensed consolidated financial statements included in this Quarterly Report).

(Gain) Loss on Disposal or Impairment of Assets, Net. During the nine months ended December 31, 2016, we recorded:


•	the reversal of $124.7 million of the previously recorded $380.2 million goodwill impairment charge recorded during the three months ended March 31, 2016 (see Note 6 to our unaudited condensed consolidated financial statements included in this Quarterly Report);


•	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 (see Note 7 to our unaudited condensed consolidated financial statements included in this Quarterly Report);


•	a loss of $22.7 million related to the termination of the development agreement, which included the carrying value of the development agreement asset that was written off (see Note 15 to our unaudited condensed consolidated financial statements included in this Quarterly Report);


•	an impairment charge of $1.7 million to write down a loan receivable from an equity method investee to its fair value as a result of acquiring the remaining ownership interest in the equity method investee during the three months ended June 30, 2016 (see Note 14 to our unaudited condensed consolidated financial statements included in this Quarterly Report); and


•	a loss of $3.1 million on the sales of certain assets and the sale of our freshwater supply company (see Note 4 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a discussion of the sale of the freshwater supply company).

During the nine months ended December 31, 2015, we recorded a loss of $0.9 million on the sale and disposal of certain assets.

Revaluation of Liabilities. The revaluation of liabilities represents the valuation adjustment of contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations during the nine months ended December 31, 2015. During the nine months ended December 31, 2016, we did not identify any significant changes in our Water Solutions operations, which would require a revaluation of the contingent consideration obligation, and as such, no adjustment was recorded.

Table of Contents

Liquids

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



	Nine Months Ended December 31,
	2016		2015			Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	458,646	$	393,442		$	65,204
Cost of sales	430,775		375,831			54,944
Product margin	27,871		17,611			10,260

Other product sales:
Revenues (1)	485,174		488,967			(3,793		)
Cost of sales	449,539		415,550			33,989
Product margin	35,635		73,417			(37,782		)

Other revenues:
Revenues (1)	22,926		27,531			(4,605		)
Cost of sales	8,069		11,212			(3,143		)
Product margin	14,857		16,319			(1,462		)

Expenses:
Operating expenses	28,386		37,108			(8,722		)
General and administrative expenses	3,461		6,318			(2,857		)
Depreciation and amortization expense	13,315		11,286			2,029
Loss (gain) on disposal or impairment of assets, net	109		(185		)	294
Total expenses	45,271		54,527			(9,256		)
Segment operating income	$	33,092	$	52,820		$	(19,728	)

Propane sold (gallons)	813,490		820,127			(6,637		)
Propane sold ($/gallon)	$	0.564	$	0.480		$	0.084
Cost per propane sold ($/gallon)	$	0.530	$	0.458		$	0.072
Propane product margin ($/gallon)	$	0.034	$	0.022		$	0.012

Other products sold (gallons)	604,309		649,909			(45,600		)
Other products sold ($/gallon)	$	0.803	$	0.752		$	0.051
Cost per other products sold ($/gallon)	$	0.744	$	0.639		$	0.105
Other products product margin ($/gallon)	$	0.059	$	0.113		$	(0.054	)


(1)	Revenues include $57.2 million and $48.4 million of intersegment sales during the nine months ended December 31, 2016 and 2015, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.

Propane Sales. The increase in revenues was due to an increase in commodity prices.

Our cost of wholesale propane sales was reduced by $1.7 million of net unrealized gains on derivatives and $0.5 million of net realized gains on derivatives during nine months ended December 31, 2016. During the nine months ended December 31, 2015, our cost of wholesale propane sales was reduced by $0.6 million of net unrealized gains on derivatives and increased by $4.0 million of net realized losses 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 nine months ended December 31, 2016 than during the nine months ended December 31, 2015. Product margins have improved because depressed market prices through

Table of Contents

last winter have led to lower inventory values to start out the new supply year. Propane prices declined during the nine months ended December 31, 2015, which had an adverse impact on product margins.

Other Products Sales. The decrease in the volume of other products sold was primarily due to reductions in production volumes as a result of low crude oil prices.

Our cost of sales of other products was increased by $2.0 million of net unrealized losses on derivatives and $4.8 million of net realized losses on derivatives during the nine months ended December 31, 2016. Our cost of sales of other products during the nine months ended December 31, 2015 was reduced by $1.6 million of net unrealized gains on derivatives and reduced by $1.3 million of net realized gains on derivatives.

Product margins during the nine months ended December 31, 2015 benefited from a high level of butane supply in the market, which lowered our product cost.

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. While railcar costs have held steady, the value we are able to realize for the railcar in the market has dropped significantly year over year.

Operating and General and Administrative Expenses. The decrease was due primarily to a reduction in overall compensation expense due to lower incentive compensation and commission expense as well as continued cost management monitoring which focuses on reductions of expenses.

Depreciation and Amortization Expense. The increase was due primarily to purchase accounting adjustments for the Sawtooth cavern acquisition during the three months ended December 31, 2015.

Table of Contents

Retail Propane

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



	Nine Months Ended December 31,
	2016			2015		Change
	(in thousands, except per gallon amounts)
Propane sales:
Revenues (1)	$	174,510		$	148,184	$	26,326
Cost of sales	70,564			55,703		14,861
Product margin	103,946			92,481		11,465

Distillate sales:
Revenues (1)	35,613			39,758		(4,145		)
Cost of sales	26,244			30,173		(3,929		)
Product margin	9,369			9,585		(216		)

Other revenues:
Revenues	30,056			29,856		200
Cost of sales	9,211			10,541		(1,330		)
Product margin	20,845			19,315		1,530

Expenses:
Operating expenses	84,628			73,793		10,835
General and administrative expenses	7,304			8,784		(1,480		)
Depreciation and amortization expense	31,771			26,711		5,060
(Gain) loss on disposal or impairment of assets, net	(96		)	108		(204		)
Total expenses	123,607			109,396		14,211
Segment operating income	$	10,553		$	11,985	$	(1,432	)

Propane sold (gallons)	105,933			89,938		15,995
Propane sold ($/gallon)	$	1.647		$	1.648	$	(0.001	)
Cost per propane sold ($/gallon)	$	0.666		$	0.619	$	0.047
Propane product margin ($/gallon)	$	0.981		$	1.029	$	(0.048	)

Distillates sold (gallons)	17,505			17,745		(240		)
Distillates sold ($/gallon)	$	2.034		$	2.241	$	(0.207	)
Cost per distillates sold ($/gallon)	$	1.499		$	1.700	$	(0.201	)
Distillates product margin ($/gallon)	$	0.535		$	0.541	$	(0.006	)


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

Revenues. The increase for propane was due to the three acquisitions in the current year as well as slightly colder weather in the current winter. The decrease for distillate revenues was primarily due to lower commodity prices during the first and second quarters of fiscal year 2017.

Cost of Sales. The increase for propane was due to current year acquisitions and an increase in commodity prices. The decrease for distillates was due to lower commodity prices in the first and second quarters of the fiscal year 2017.

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

Table of Contents

Depreciation and Amortization Expense. The increase was due primarily to acquisitions of retail propane businesses.

Refined Products and Renewables



	Nine Months Ended December 31,
	2016			2015		Change
	(in thousands, except per barrel and per gallon amounts)
Refined products sales:
Revenues (1)	$	6,409,889		$	4,946,136	$	1,463,753
Cost of sales	6,353,792			4,859,519		1,494,273
Product margin	56,097			86,617		(30,520		)

Renewables sales:
Revenues	325,377			300,756		24,621
Cost of sales	320,695			290,348		30,347
Product margin	4,682			10,408		(5,726		)

Service fee revenues	11,195			89,193		(77,998		)

Expenses:
Operating expenses	19,861			76,209		(56,348		)
General and administrative expenses	7,612			13,632		(6,020		)
Depreciation and amortization expense	1,237			36,820		(35,583		)
(Gain) loss on disposal or impairment of assets, net	(126,101		)	79		(126,180		)
Total (income) expense, net	(97,391		)	126,740		(224,131		)
Segment operating income	$	169,365		$	59,478	$	109,887

Refined products sold (barrels)	103,693			71,209		32,484
Refined products sold ($/barrel)	$	61.816		$	69.459	$	(7.643	)
Cost per refined products sold ($/barrel)	$	61.275		$	68.243	$	(6.968	)
Refined products product margin ($/barrel)	$	0.541		$	1.216	$	(0.675	)
Refined products product margin ($/gallon)	$	0.013		$	0.029	$	(0.016	)

Renewable products sold (barrels)	5,138			4,144		994
Renewable products sold ($/barrel)	$	63.328		$	72.576	$	(9.248	)
Cost per renewable products sold ($/barrel)	$	62.416		$	70.065	$	(7.649	)
Renewable products product margin ($/barrel)	$	0.912		$	2.511	$	(1.599	)
Renewable products product margin ($/gallon)	$	0.022		$	0.060	$	(0.038	)


(1)	Revenues include $0.3 million and $0.7 million of intersegment sales during the nine months ended December 31, 2016 and 2015, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.

Refined Products Sales and Cost of Sales. The increase in revenues and cost of sales was due to increased volumes, partially offset by a decrease in refined products prices. The increased volumes were due primarily to an increase in pipeline capacity rights purchased during the fiscal year ended March 31, 2016 and nine months ended December 31, 2016, an expansion of our refined products operations, and the continued demand for motor fuels in the current low gasoline price environment. Product margins during the nine months ended December 31, 2016 were negatively impacted by losses on our derivative and risk management contracts due to NYMEX prices increasing during the three months ended December 31, 2016.

Table of Contents

Our inventories are carried at the lower of cost or market while our derivative and risk management contracts are carried at fair value. As a result, if refined product prices are increasing during the quarter, we report losses on derivative and risk management contracts in our unaudited condensed consolidated statement of operations and any gains on inventory would not be realized until the inventory is sold the following quarter. Product margin during the nine months ended December 31, 2016 was also impacted by storage fees paid to TLP which are no longer eliminated as TLP was deconsolidated on February 1, 2016.

Renewables Sales. The increase in revenues was due to increased volumes, partially offset by decrease in renewables prices. The increased volumes were due primarily to being able to liquidate storage volumes as the renewables markets shifted from being in contango (a condition in which forward renewables prices are greater than spot prices) to being backwardated (a condition in which forward renewables prices are lower than spot prices) during the nine months ended December 31, 2016. Per-barrel product margins were lower during the nine months ended December 31, 2016, compared to the nine months ended December 31, 2015 as a result of the biodiesel tax credit being in place for the entire 2016 calendar year, compared to being reinstated in December 2015 for the 2015 calendar year.

Service Fee Revenues, Operating Expenses, General and Administrative Expenses, Depreciation and Amortization Expense. The decrease in each of these line items was due primarily to the inclusion of TLP for the nine months ended December 31, 2015 with no comparable activity in the current period, as TLP was deconsolidated on February 1, 2016.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the nine months ended December 31, 2016, we recognized a $104.1 million gain from the sale of all of the TLP units we owned. During the nine months ended December 31, 2016, we recognized $22.6 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 nine months ended December 31, 2016, we recorded a loss of $0.6 million on the sales of certain assets. During the nine months ended December 31, 2015, we recorded a loss of $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:



	Nine Months Ended December 31,
	2016			2015			Change
	(in thousands)
Other revenues:
Revenues	$	679		$	—		$	679
Cost of sales	300			—			300
Margin	379			—			379

Expenses:
Operating expenses	935			(84		)	1,019
General and administrative expenses	63,394			77,761			(14,367		)
Depreciation and amortization expense	2,744			3,953			(1,209		)
Gain on disposal or impairment of assets, net	(4		)	—			(4		)
Total expenses	67,069			81,630			(14,561		)
Operating loss	$	(66,690	)	$	(81,630	)	$	14,940

General and Administrative Expenses. The decrease was due primarily to lower equity-based compensation expense. For our performance units, we recorded expense of $5.2 million during the nine months ended December 31, 2016, compared to $16.3 million during the nine months ended December 31, 2015. The nine months ended December 31, 2015 included the initial grant and vesting of the first tranche of the performance units. The expense associated with the service award units (exclusive of accruals of annual bonuses paid or expected to be paid in common units) was $32.5 million during the nine months ended December 31, 2016, compared to $23.4 million during the nine months ended December 31, 2015. The increase was due primarily to us no longer needing to revalue our unvested units as we changed our process for the withholding of taxes on vesting. During the nine months ended December 31, 2015, the value of the unvested units was reduced due to declines in our unit price and resulted in the reversal of previously recorded compensation expense. See Note 11 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion of our equity-based compensation awards.

Table of Contents

Equity in Earnings of Unconsolidated Entities

The decrease of $12.3 million during the nine months ended December 31, 2016 was due primarily to a decrease of $10.7 million of earnings from TLP (including BOSTCO and Frontera) that we acquired as part of our July 2014 acquisition of TransMontaigne. On February 1, 2016, we deconsolidated TLP when we sold our general partner interest in TLP, and on April 1, 2016, we sold all of the TLP common units we owned. Also contributing to this decrease was a decrease of $1.5 million in earnings from our investments in Glass Mountain and an ethanol production facility.

Revaluation of Investments

On June 3, 2016, we acquired the remaining 65% ownership interest in a freshwater supply company. Prior to the completion of this transaction, we accounted for our previously held 35% ownership interest of this freshwater supply company using the equity method of accounting (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report). As we owned a controlling interest in this entity, 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 gain on bargain purchase of $0.6 million.

Interest Expense

The increase of $6.8 million during the nine months ended December 31, 2016 was due primarily to the increased level of debt outstanding on our Revolving Credit Facility (as defined herein) (the average balance outstanding on our Revolving Credit Facility was $1.8 billion during the nine months ended December 31, 2016, compared to $1.7 billion during the nine months ended December 31, 2015), primarily to finance acquisitions and capital expenditures, as well as the issuance of $700.0 million of fixed-rate notes during October 2016, partially offset by lower interest expense related to TLP’s credit facility (our interest in TLP was acquired in July 2014, and we deconsolidated TLP as of February 1, 2016) and lower interest expense as we repurchased a portion of the 2019 Notes (as defined herein) and 2021 Notes (as defined herein) during the three months ended March 31, 2016 and the three months ended June 30, 2016.

Gain on Early Extinguishment of Liabilities

During the nine months ended December 31, 2016, we repurchased $5.0 million of our 2019 Notes (as defined herein) and $19.2 million of our 2021 Notes (as defined herein) for an aggregate purchase price of $15.1 million (excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of these notes of $8.6 million (net of the write off of debt issuance costs of $0.5 million).

As discussed in Note 15 to our unaudited condensed consolidated financial statements included in this Quarterly Report, we accounted for the termination of the development agreement as an acquisition of assets (see Note 7 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion) and recorded a gain of $21.3 million on the release of $46.8 million of contingent consideration liabilities.

During the nine months ended December 31, 2016, we acquired certain parcels of land on which one of our water solutions facilities is located and recorded a gain of $0.9 million on the release of certain contingent consideration liabilities.

Table of Contents

Other Income, Net

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



	Nine Months Ended December 31,
	2016			2015
	(in thousands)
Interest income (1)	$	6,341		$	9,422
Crude oil marketing arrangement (2)	(1,512		)	(6,386		)
Termination of storage sublease agreement (3)	16,205			—
Other (4)	4,826			(95		)
Other income, net	$	25,860		$	2,941

(1)


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

(3)

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


(4)	Relates primarily to a distribution from TLP pursuant to the agreement to sell all of the TLP common units we owned in April 2016, a gain on insurance settlement from damage to two facilities in our Water Solutions segment and a payment received related to a contract termination.

Income Tax Expense (Benefit)

Income tax expense was $2.0 million during the nine months ended December 31, 2016, compared to an income tax benefit of $1.8 million during the nine months ended December 31, 2015. Income tax benefit during the nine months ended December 31, 2015 included a benefit of $3.6 million related to a change in estimate of the income tax obligation payable related to TransMontaigne. See Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Noncontrolling Interests

The decrease of $8.6 million during the nine months ended December 31, 2016 was due primarily to the deconsolidation of TLP on February 1, 2016 as a result of the sale of our general partner interest in TLP, partially offset by adjustments related to noncontrolling interests.

Liquidity, Sources of Capital and Capital Resource Activities

Our principal sources of liquidity and capital are the cash flows from our operations and borrowings under our Revolving Credit Facility. 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.

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

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

Table of Contents

We believe that our anticipated cash flows from operations and the borrowing capacity under our Revolving Credit Facility are sufficient to meet our liquidity needs. If our plans or assumptions change or are inaccurate, or if we make acquisitions, we may need to raise additional capital 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.

In January 2017, we announced that our management team expects to recommend a distribution of $1.76 per common unit annualized for the quarter ended March 31, 2017 and to grow the distribution to $2.00 per common unit annualized during the year. Based on current market conditions and commodity prices, our management team expects the distribution to grow approximately 10% for the three years after fiscal year 2018. At these distribution levels, we expect to generate significant excess cash flow to be able to reinvest in our business and reduce indebtedness.

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, asset sales or other forms of financing.

Other sources of liquidity during the nine months ended December 31, 2016 are discussed below.

Sale of TLP Common Units

On April 1, 2016, we sold all of the TLP common units we owned to ArcLight Capital Partners for approximately $112.4 million in cash and recorded a gain on disposal of $104.1 million during the nine months ended December 31, 2016.

Class A Convertible Preferred Units

During the nine months ended December 31, 2016, we issued $240 million of 10.75% Class A Convertible Preferred Units (“Preferred Units”) to Oaktree Capital Management L.P. and its co-investors. See Note 11 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further description of the Preferred Units.

At-The-Market Program

On August 24, 2016, we entered into an equity distribution program in connection with an at-the-market program (the “ATM Program”) pursuant to which we may issue and sell common units for up to $200.0 million in gross proceeds. We are under no obligation to issue equity under the ATM Program. We intend to use the net proceeds from any sales under the ATM Program for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. During the nine months ended December 31, 2016, we sold 2,353,438 common units for net proceeds of $43.9 million (net of offering costs of $0.3 million).

Subsequent to December 31, 2016, we sold an additional 967,697 common units for net proceeds of $20.5 million (net of offering costs of $0.2 million).

2023 Notes

On October 24, 2016, we entered into the 2023 Note Purchase Agreement whereby we issued $700.0 million of the 2023 Notes in a private placement. The 2023 Notes bear interest at 7.50%, which is payable on May 1 and November 1 of each year, beginning on May 1, 2017. We received net proceeds of $687.9 million, after the initial purchasers’ discount of $10.5 million and offering costs of $1.6 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility (as defined herein). See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further description of these notes.

Table of Contents

Long-Term Debt

Credit Agreement

At December 31, 2016, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

At December 31, 2016, we were in compliance with the covenants under the indenture governing the 2019 Notes.

2021 Notes

Table of Contents

At December 31, 2016, we were in compliance with the covenants under the indenture governing the 2021 Notes.

2022 Notes

At December 31, 2016, we were in compliance with the covenants under the 2022 Note Purchase Agreement.

2023 Notes

On October 24, 2016, we entered into the 2023 Note Purchase Agreement whereby we issued $700.0 million of the 2023 Notes in a private placement. The 2023 Notes bear interest at 7.50%, which is payable on May 1 and November 1 of each year, beginning on May 1, 2017. We received net proceeds of $687.9 million, after the initial purchasers’ discount of $10.5 million and offering costs of $1.6 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility. The 2023 Notes mature on November 1, 2023. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further description of these notes.

At December 31, 2016, we were in compliance with the covenants under the 2023 Note Purchase Agreement.

Revolving Credit Balances

The following table summarizes our revolving credit facility borrowings for the periods indicated:



	Average Balance Outstanding		Lowest Balance		Highest Balance
	(in thousands)
Nine Months Ended December 31, 2016
Expansion capital borrowings	$	1,133,071	$	638,000	$	1,359,000
Working capital borrowings	$	662,660	$	465,500	$	875,500

Nine Months Ended December 31, 2015
Expansion capital borrowings	$	1,012,918	$	739,500	$	1,380,000
Working capital borrowings	$	651,096	$	546,000	$	756,000
TLP credit facility borrowings	$	253,593	$	244,000	$	263,400

Table of Contents

Capital Expenditures

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



	Capital Expenditures
	Expansion (1)		Maintenance (2)		Total
	(in thousands)
Three Months Ended December 31,
2016	$	60,330	$	5,205	$	65,535
2015	$	258,609	$	13,140	$	271,749

Nine Months Ended December 31,
2016	$	246,167	$	17,901	$	264,068
2015	$	459,141	$	39,146	$	498,287


(1)	Includes expansion capital expenditures for TLP of $1.1 million during the three months ended December 31, 2015 and $10.4 million during the nine months ended December 31, 2015.


(2)	Includes maintenance capital expenditures for TLP of $4.3 million during the three months ended December 31, 2015 and $11.4 million during the nine months ended December 31, 2015.

Cash Flows

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



	Nine Months Ended December 31,
Cash Flows Provided by (Used in)	2016			2015
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	194,858		$	121,713
Changes in operating assets and liabilities	(312,523		)	171,421
Operating activities	$	(117,665	)	$	293,134
Investing activities	$	(331,070	)	$	(595,101	)
Financing activities	$	449,486		$	285,843

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.

Investing Activities. Net cash used in investing activities was $331.1 million during the nine months ended December 31, 2016, compared to $595.1 million during the nine months ended December 31, 2015. The decrease in net cash used in investing activities was due primarily to:


•	a decrease in capital expenditures from $497.1 million during the nine months ended December 31, 2015 to $264.6 million during the nine months ended December 31, 2016;


•	$112.4 million in proceeds received from the sale of the TLP common units we owned during the nine months ended December 31, 2016;


•	a $59.8 million decrease in cash paid for acquisitions during the nine months ended December 31, 2016;

Table of Contents


•	$22.0 million in proceeds received from the sale of our freshwater supply company during the nine months ended December 31, 2016; and


•	a $12.9 million decrease related to a loan receivable from an equity method investee as we purchased the remaining ownership interest in this equity method investee and, therefore, consolidated this previous equity method investee in our unaudited condensed consolidated financial statements during the three months ended June 30, 2016.

These decreases were partially offset by:


•	a $175.0 million increase in cash flows from derivatives; and


•	a $16.9 million payment to terminate the development agreement (see Note 15 to our unaudited condensed consolidated financial statements included in this Quarterly Report).

Financing Activities. Net cash provided by financing activities was $449.5 million during the nine months ended December 31, 2016, compared to $285.8 million during the nine months ended December 31, 2015. The increase in net cash provided by financing activities was due primarily to:


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


•	$235.0 million in proceeds received (net of offering costs) from the sale of our Preferred Units and warrants during the nine months ended December 31, 2016; and


•	a decrease of $129.6 million in distributions paid to our partners and noncontrolling interest owners during the nine months ended December 31, 2016.

These increases were partially offset by:


•	an $862.5 million decrease in borrowings on our revolving credit facilities (net of repayments) during the nine months ended December 31, 2016;


•	$53.2 million in proceeds from other long-term debt during the nine months ended December 31, 2015;


•	a $25.9 million release of contingent consideration liabilities related to the termination of the development agreement during the nine months ended December 31, 2016 (see Note 15 to our unaudited condensed consolidated financial statements included in this Quarterly Report); and


•	$15.1 million in repurchases of a portion of our outstanding senior notes during the nine months ended December 31, 2016.

The following table summarizes distributions declared during our current and prior fiscal years:



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, 2015	May 5, 2015	May 15, 2015	$	0.6250	$	59,651	$	13,446
July 23, 2015	August 3, 2015	August 14, 2015	$	0.6325	$	66,248	$	15,483
October 22, 2015	November 3, 2015	November 13, 2015	$	0.6400	$	67,313	$	16,277
January 21, 2016	February 3, 2016	February 15, 2016	$	0.6400	$	67,310	$	16,279
April 21, 2016	May 3, 2016	May 13, 2016	$	0.3900	$	40,626	$	70
July 22, 2016	August 4, 2016	August 12, 2016	$	0.3900	$	41,146	$	71
October 20, 2016	November 4, 2016	November 14, 2016	$	0.3900	$	41,907	$	72
January 19, 2017	February 3, 2017	February 14, 2017	$	0.3900	$	42,923	$	74

Distributions on the Partnership’s outstanding Class A Convertible Preferred Units are declared and paid quarterly. On July 22, 2016, $1.8 million of distributions were declared and paid to the holders of the Preferred Units on August 12, 2016. On October 20, 2016, $6.4 million of distributions were declared and paid to the holders of the Preferred Units on November 14,

Table of Contents

2016. On January 19, 2017, we declared a distribution of $6.4 million to be paid to the holders of the Preferred Units on February 14, 2017.

Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2016 for our fiscal years ending thereafter:



			Three Months Ending March 31,		Year Ending March 31,
	Total		2017		2018		2019		2020		2021		Thereafter
	(in thousands)
Principal payments on long-term debt:
Expansion capital borrowings	$	638,000	$	—	$	—	$	638,000	$	—	$	—	$	—
Working capital borrowings	875,500		—		—		875,500		—		—		—
2019 Notes	383,467		—		—		—		383,467		—		—
2021 Notes	369,063		—		—		—		—		—		369,063
2022 Notes	250,000		—		25,000		50,000		50,000		50,000		75,000
2023 Notes	700,000		—		—		—		—		—		700,000
Other long-term debt	58,550		1,437		8,234		7,106		6,594		34,902		277
Interest payments on long-term debt:
Revolving Credit Facility (1)	110,274		26,199		52,547		31,528		—		—		—
2019 Notes	58,958		9,826		19,653		19,653		9,826		—		—
2021 Notes	126,865		—		25,373		25,373		25,373		25,373		25,373
2022 Notes	54,031		4,156		16,209		13,300		9,975		6,650		3,741
2023 Notes	368,251		—		53,251		52,500		52,500		52,500		157,500
Other long-term debt	11,628		667		3,558		3,030		2,580		1,782		11
Letters of credit	79,552		—		—		79,552		—		—		—
Future minimum lease payments under noncancelable operating leases	608,774		34,952		134,262		111,760		100,450		87,197		140,153
Future minimum throughput payments under noncancelable agreements (2)	167,480		13,534		54,365		53,688		43,856		1,438		599
Construction commitments (3)	43,656		15,292		28,364		—		—		—		—
Fixed-price commodity purchase commitments (4)	196,003		194,994		1,009		—		—		—		—
Index-price commodity purchase commitments (5)	1,698,771		633,929		440,270		280,361		344,211		—		—
Total contractual obligations	$	6,798,823	$	934,986	$	862,095	$	2,241,351	$	1,028,832	$	259,842	$	1,471,717


(1)	The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at December 31, 2016. 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 and refined products 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.


(3)	At December 31, 2016, construction commitments relate to the Glass Mountain pipeline extension and additional projects at Cushing, Oklahoma related to our Grand Mesa Pipeline project, certain crude oil terminals and an expansion of a salt dome cavern.

(4) At December 31, 2016, we had the following fixed-price purchase commitments (in thousands):



	Crude Oil			Natural Gas Liquids
	Value		Volume (in barrels)	Value		Volume (in gallons)
2017 (three months)	$	186,499	3,671	$	8,495	14,863
2018	—		—	1,009		2,268
Total	$	186,499	3,671	$	9,504	17,131

Table of Contents

(5) At December 31, 2016, we had the following index-price purchase commitments (in thousands):



	Crude Oil			Natural Gas Liquids
	Value		Volume (in barrels)	Value		Volume (in gallons)
2017 (three months)	$	407,427	8,161	$	226,502	302,579
2018	423,776		8,517	16,494		20,132
2019	280,361		5,658	—		—
2020	344,211		10,991	—		—
Total	$	1,455,775	33,327	$	242,996	322,711

Index prices are based on a forward price curve at December 31, 2016. A theoretical change of $0.10 per gallon in the underlying commodity price at December 31, 2016 would result in a change of $32.3 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel in the underlying commodity price at December 31, 2016 would result in a change of $33.3 million in the value of our index-price crude oil purchase commitments.

Sales Contracts

We have entered into product sales contracts for which we expect the parties to physically settle the inventory in future periods. At December 31, 2016, we had the following sales contract volumes (in thousands):



Natural gas liquids fixed-price (gallons)		119,108
Natural gas liquids index-price (gallons)		205,672
Crude oil fixed-price (barrels)		4,797
Crude oil index-price (barrels)		15,157

Off-Balance Sheet Arrangements

We do not have any off balance sheet arrangements other than the operating leases discussed in Note 10 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 the Partnership’s 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.

Table of Contents

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

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

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At December 31, 2016, we had $1.5 billion of outstanding borrowings under our Revolving Credit Facility at a weighted average interest rate of 3.39%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.9 million, based on borrowings outstanding at December 31, 2016.

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 products will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract.

Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions. At December 31, 2016, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.

The crude oil, natural gas liquids, and refined 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 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. The following table summarizes the hypothetical impact on the December 31, 2016 fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands):



	Increase (Decrease) To Fair Value
Crude oil (Crude Oil Logistics segment)	$	(3,564	)
Crude oil (Water Solutions segment)	$	(15	)
Propane (Liquids segment)	$	421
Other products (Liquids segment)	$	(201	)
Refined products (Refined Products and Renewables segment)	$	(40,793	)
Renewables (Refined Products and Renewables segment)	$	(4,148	)
Canadian dollars (Liquids segment)	$	807

Table of Contents

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 participation of our management, including the principal executive officer and principal financial officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures at December 31, 2016. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of December 31, 2016, such disclosure controls and procedures were effective to provide the reasonable assurance discussed above.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) of the Exchange Act) during the three months ended December 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Table of Contents

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 10 to our unaudited condensed consolidated financial statements in Part I, Item 1, of this Quarterly Report on Form 10-Q, which information is incorporated by reference into this Item 1.

Item 1A. Risk Factors

There have been no material changes 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, 2016, 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, 2016.

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

None.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Table of Contents

Item 6. Exhibits



Exhibit Number		Exhibit
4.1		Indenture, dated as of October 24, 2016, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 24, 2016)
4.2		Forms of 7.5% Senior Notes due 2023 (incorporated by reference to Exhibit 4.2 and included as Exhibits A1 and A2 to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 24, 2016)
4.3		Registration Rights Agreement, dated as of October 24, 2016, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the guarantors listed therein on Exhibit A and Barclays Capital Inc. as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 24, 2016)
12.1	*	Computation of ratios of earnings to fixed charges and combined fixed charges and preferred unit distributions
31.1	*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	**	XBRL Instance Document
101.SCH	**	XBRL Schema Document
101.CAL	**	XBRL Calculation Linkbase Document
101.DEF	**	XBRL Definition Linkbase Document
101.LAB	**	XBRL Label Linkbase Document
101.PRE	**	XBRL Presentation Linkbase Document


*	Exhibits filed with this report.

The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Unaudited Condensed Consolidated Balance Sheets at December 31, 2016 and March 31, 2016, (ii) Unaudited Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2016 and 2015, (iii) Unaudited Condensed Consolidated Statements of Comprehensive Income for the three months and nine months ended December 31, 2016 and 2015, (iv) Unaudited Condensed Consolidated Statement of Changes in Equity for the nine months ended December 31, 2016, (v) Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2016 and 2015, and (vi) Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	NGL ENERGY PARTNERS LP

	By:	NGL Energy Holdings LLC, its general partner

Date: February 7, 2017		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer

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

Table of Contents

INDEX TO EXHIBITS



Exhibit Number		Exhibit
4.1		Indenture, dated as of October 24, 2016, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 24, 2016)
4.2		Forms of 7.5% Senior Notes due 2023 (incorporated by reference to Exhibit 4.2 and included as Exhibits A1 and A2 to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 24, 2016)
4.3		Registration Rights Agreement, dated as of October 24, 2016, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the guarantors listed therein on Exhibit A and Barclays Capital Inc. as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 24, 2016)
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.