NGL 10-Q Quarterly Report Dec. 31, 2015

NGL ENERGY PARTNERS LP

10-Ks and 10-Qs

10-Q	Quarter ended Sept. 30, 2025
10-Q	Quarter ended June 30, 2025
10-K	Fiscal year ended March 31, 2025
10-Q	Quarter ended Dec. 31, 2024
10-Q	Quarter ended Sept. 30, 2024
10-Q	Quarter ended June 30, 2024
10-K	Fiscal year ended March 31, 2024
10-Q	Quarter ended Dec. 31, 2023
10-Q	Quarter ended Sept. 30, 2023
10-Q	Quarter ended June 30, 2023
10-K	Fiscal year ended March 31, 2023
10-Q	Quarter ended Dec. 31, 2022
10-Q	Quarter ended Sept. 30, 2022
10-Q	Quarter ended June 30, 2022
10-K	Fiscal year ended March 31, 2022
10-Q	Quarter ended Dec. 31, 2021
10-Q	Quarter ended Sept. 30, 2021
10-Q	Quarter ended June 30, 2021
10-K	Fiscal year ended March 31, 2021
10-Q	Quarter ended Dec. 31, 2020
10-Q	Quarter ended Sept. 30, 2020
10-Q	Quarter ended June 30, 2020
10-K	Fiscal year ended March 31, 2020
10-Q	Quarter ended Dec. 31, 2019
10-Q	Quarter ended Sept. 30, 2019
10-Q	Quarter ended June 30, 2019
10-K	Fiscal year ended March 31, 2019
10-Q	Quarter ended Dec. 31, 2018
10-Q	Quarter ended Sept. 30, 2018
10-Q	Quarter ended June 30, 2018
10-K	Fiscal year ended March 31, 2018
10-Q	Quarter ended Dec. 31, 2017
10-Q	Quarter ended Sept. 30, 2017
10-Q	Quarter ended June 30, 2017
10-K	Fiscal year ended March 31, 2017
10-Q	Quarter ended Dec. 31, 2016
10-Q	Quarter ended Nov. 4, 2016
10-Q	Quarter ended June 30, 2016
10-K	Fiscal year ended March 31, 2016
10-Q	Quarter ended Dec. 31, 2015
10-Q	Quarter ended Sept. 30, 2015
10-Q	Quarter ended June 30, 2015
10-K	Fiscal year ended March 31, 2015
10-Q	Quarter ended Dec. 31, 2014
10-Q	Quarter ended Sept. 30, 2014
10-Q	Quarter ended June 30, 2014
10-K	Fiscal year ended March 31, 2014
10-Q	Quarter ended Dec. 31, 2013
10-Q	Quarter ended Sept. 30, 2013
10-Q	Quarter ended June 30, 2013
10-K	Fiscal year ended March 31, 2013
10-Q	Quarter ended Dec. 31, 2012
10-Q	Quarter ended Sept. 30, 2012
10-Q	Quarter ended June 30, 2012
10-K	Fiscal year ended March 31, 2012
10-Q	Quarter ended Dec. 31, 2011
10-Q	Quarter ended Sept. 30, 2011
10-Q	Quarter ended June 30, 2011
10-K	Fiscal year ended March 31, 2011

10-Q 1 a16-1830_110q.htm 10-Q

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, 2015

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

For the transition period from to

Commission File Number: 001-35172

NGL Energy Partners LP

(Exact Name of Registrant as Specified in Its Charter)

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

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

(918) 481-1119

(Registrant’s Telephone Number, Including Area Code)

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

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

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

Large accelerated filer x		Accelerated filer o

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

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

At February 2, 2016, there were 107,063,269 common units issued and outstanding.

Table of Contents

TABLE OF CONTENTS

PART I

Item 1.	Financial Statements (Unaudited)	3

	Condensed Consolidated Balance Sheets at December 31, 2015 and March 31, 2015	3

	Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2015 and 2014	4

	Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and nine months ended December 31, 2015 and 2014	5

	Condensed Consolidated Statement of Changes in Equity for the nine months ended December 31, 2015	6

	Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2015 and 2014	7

	Notes to Unaudited Condensed Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	53

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	100

Item 4.	Controls and Procedures	101

PART II

Item 1.	Legal Proceedings	102

Item 1A.	Risk Factors	102

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	102

Item 3.	Defaults Upon Senior Securities	102

Item 4.	Mine Safety Disclosures	102

Item 5.	Other Information	102

Item 6.	Exhibits	103

SIGNATURES		104

INDEX TO EXHIBITS		105

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 impact 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 impacts 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 impact of energy conservation efforts on product demand;

· energy efficiencies and technological trends;

· governmental regulation and taxation;

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

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

Table of Contents

· 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 hire drivers;

· the ability to renew contracts with key customers;

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

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

· 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 impact 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 required by state and federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events, or otherwise. When considering forward-looking statements, please review the risks described under Part I, Item 1A —“Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended March 31, 2015.

Table of Contents

PART I

Item 1. Financial Statements (Unaudited)

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Balance Sheets

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

	December 31,			March 31,
	2015			2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	25,179		$	41,303
Accounts receivable—trade, net of allowance for doubtful accounts of $6,270 and $4,367, respectively	581,621			1,024,226
Accounts receivable—affiliates	3,812			17,198
Inventories	414,088			441,762
Prepaid expenses and other current assets	117,476			120,855
Assets held for sale	87,383			—
Total current assets	1,229,559			1,645,344

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $305,233 and $202,959, respectively	1,972,925			1,617,389
GOODWILL	1,522,644			1,402,761
INTANGIBLE ASSETS, net of accumulated amortization of $305,891 and $220,517, respectively	1,242,440			1,288,343
INVESTMENTS IN UNCONSOLIDATED ENTITIES	467,559			472,673
LOAN RECEIVABLE—AFFILIATE	23,258			8,154
OTHER NONCURRENT ASSETS	106,086			112,837
Total assets	$	6,564,471		$	6,547,501

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable—trade	$	511,309		$	833,380
Accounts payable—affiliates	11,042			25,794
Accrued expenses and other payables	193,295			195,116
Advance payments received from customers	73,662			54,234
Current maturities of long-term debt	7,600			4,472
Total current liabilities	796,908			1,112,996

LONG-TERM DEBT, net of current maturities	3,323,492			2,745,299
OTHER NONCURRENT LIABILITIES	13,232			16,086

COMMITMENTS AND CONTINGENCIES (NOTE 11)

EQUITY:
General partner, representing a 0.1% interest, 105,489 and 103,899 notional units, respectively	(34,431		)	(37,021		)
Limited partners, representing a 99.9% interest, 105,383,639 and 103,794,870 common units issued and outstanding, respectively	1,920,528			2,162,924
Accumulated other comprehensive loss	(148		)	(109		)
Noncontrolling interests	544,890			547,326
Total equity	2,430,839			2,673,120
Total liabilities and equity	$	6,564,471		$	6,547,501

The accompanying notes are an integral part of these 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)

	Three Months Ended December 31,						Nine Months Ended December 31,
	2015			2014			2015			2014
REVENUES:
Crude oil logistics	$	519,425		$	1,694,881		$	2,854,787		$	5,735,307
Water solutions	45,438			50,241			147,225			150,274
Liquids	353,527			685,096			861,504			1,700,006
Retail propane	100,145			139,765			217,798			286,025
Refined products and renewables	1,666,471			1,983,444			5,335,356			5,708,161
Other	—			(1,281		)	—			1,513
Total Revenues	2,685,006			4,552,146			9,416,670			13,581,286

COST OF SALES:
Crude oil logistics	495,529			1,697,374			2,770,240			5,678,725
Water solutions	(3,128		)	(29,085		)	(8,088		)	(27,951		)
Liquids	300,766			657,010			754,157			1,633,090
Retail propane	45,974			81,172			96,417			168,590
Refined products and renewables	1,594,359			1,905,021			5,149,151			5,570,185
Other	—			176			—			2,547
Total Cost of Sales	2,433,500			4,311,668			8,761,877			13,025,186

OPERATING COSTS AND EXPENSES:
Operating	106,783			97,761			314,470			262,616
General and administrative	23,035			44,230			114,814			113,742
Depreciation and amortization	59,180			50,335			175,772			139,809
Loss on disposal or impairment of assets, net	1,328			30,073			3,040			34,639
Operating Income	61,180			18,079			46,697			5,294

OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	2,858			1,242			14,008			7,504
Interest expense	(36,176		)	(30,051		)	(98,549		)	(79,196		)
Other income, net	2,161			3,371			2,941			2,363
Income (Loss) Before Income Taxes	30,023			(7,359		)	(34,903		)	(64,035		)

INCOME TAX (EXPENSE) BENEFIT	(402		)	2,090			1,846			2,977

Net Income (Loss)	29,621			(5,269		)	(33,057		)	(61,058		)

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER	(16,217		)	(11,783		)	(47,742		)	(32,220		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(6,140		)	(5,649		)	(12,906		)	(9,059		)

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	7,264		$	(22,701	)	$	(93,705	)	$	(102,337	)

BASIC INCOME (LOSS) PER COMMON UNIT	$	0.07		$	(0.26	)	$	(0.89	)	$	(1.17	)

DILUTED INCOME (LOSS) PER COMMON UNIT	$	0.03		$	(0.26	)	$	(0.89	)	$	(1.17	)

BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	105,338,200			88,545,764			104,808,649			83,702,571

DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING	106,194,547			88,545,764			104,808,649			83,702,571

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)

(U.S. Dollars in Thousands)

	Three Months Ended December 31,						Nine Months Ended December 31,
	2015			2014			2015			2014

Net income (loss)	$	29,621		$	(5,269	)	$	(33,057	)	$	(61,058	)
Other comprehensive income (loss)	(12		)	(16		)	(39		)	147
Comprehensive income (loss)	$	29,609		$	(5,285	)	$	(33,096	)	$	(60,911	)

The accompanying notes are an integral part of these 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, 2015

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

									Accumulated
				Limited Partners					Other
	General			Common					Comprehensive			Noncontrolling			Total
	Partner			Units		Amount			Loss			Interests			Equity
BALANCES AT MARCH 31, 2015	$	(37,021	)	103,794,870		$	2,162,924		$	(109	)	$	547,326		$	2,673,120
Distributions	(45,206		)	—		(193,208		)	—			(26,638		)	(265,052		)
Contributions	54			—		—			—			10,037			10,091
Business combinations	—			833,454		19,098			—			—			19,098
Equity issued pursuant to incentive compensation plan	—			1,153,456		33,160			—			—			33,160
Common unit repurchases	—			(398,141	)	(7,707		)	—			—			(7,707		)
Net income (loss)	47,742			—		(93,705		)	—			12,906			(33,057		)
Other comprehensive loss	—			—		—			(39		)	—			(39		)
TLP equity-based compensation	—			—		—			—			1,301			1,301
Other	—			—		(34		)	—			(42		)	(76		)
BALANCES AT DECEMBER 31, 2015	$	(34,431	)	105,383,639		$	1,920,528		$	(148	)	$	544,890		$	2,430,839

The accompanying notes are an integral part of these 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)

	Nine Months Ended December 31,
	2015			2014
OPERATING ACTIVITIES:
Net loss	$	(33,057	)	$	(61,058	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization, including amortization of debt issuance costs	191,081			152,228
Non-cash equity-based compensation expense	50,080			13,384
Loss on disposal or impairment of assets, net	3,040			34,639
Provision for doubtful accounts	3,770			2,398
Net commodity derivative gain	(97,069		)	(240,992		)
Equity in earnings of unconsolidated entities	(14,008		)	(7,504		)
Distributions of earnings from unconsolidated entities	15,742			9,073
Other	(40		)	5,275
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable—trade	441,300			(574,658		)
Accounts receivable—affiliates	13,386			(34,576		)
Inventories	29,236			154,607
Prepaid expenses and other assets	19,806			(50,510		)
Accounts payable—trade	(322,582		)	679,945
Accounts payable—affiliates	(14,752		)	(64,149		)
Accrued expenses and other liabilities	(10,064		)	24,314
Advance payments received from customers	17,265			39,424
Net cash provided by operating activities	293,134			81,840

INVESTING ACTIVITIES:
Purchases of long-lived assets	(497,147		)	(135,435		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	(187,356		)	(1,114,045		)
Cash flows from commodity derivatives	92,216			190,455
Proceeds from sales of assets	4,981			15,236
Investments in unconsolidated entities	(8,373		)	(33,528		)
Distributions of capital from unconsolidated entities	14,043			8,736
Loan for natural gas liquids facility	(3,913		)	(45,855		)
Payments on loan for natural gas liquids facility	5,552			—
Loan to affiliate	(15,621		)	—
Payments on loan to affiliate	517			—
Other	—			(66		)
Net cash used in investing activities	(595,101		)	(1,114,502		)

FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	2,042,100			3,096,700
Payments on revolving credit facilities	(1,514,100		)	(2,604,700		)
Issuance of notes	—			400,000
Proceeds from borrowings under other long-term debt	53,223			—
Payments on other long-term debt	(3,649		)	(5,476		)
Debt issuance costs	(9,684		)	(10,826		)
Contributions from general partner	54			408
Contributions from noncontrolling interest owners	10,037			—
Distributions to partners	(238,414		)	(176,051		)
Distributions to noncontrolling interest owners	(26,638		)	(17,497		)
Taxes paid on behalf of equity incentive plan participants	(19,303		)	—
Common unit repurchases	(7,707		)	—
Proceeds from sale of common units, net of offering costs	—			370,376
Other	(76		)	(156		)
Net cash provided by financing activities	285,843			1,052,778
Net increase (decrease) in cash and cash equivalents	(16,124		)	20,116
Cash and cash equivalents, beginning of period	41,303			10,440
Cash and cash equivalents, end of period	$	25,179		$	30,556

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

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, 2015, 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, barges, and towboats, and interests in two crude oil pipelines. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

· Our water solutions segment, the assets of which include water pipelines, water treatment and disposal facilities, washout facilities, and solid waste disposal facilities. Our water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, from the sale of recycled water and recovered hydrocarbons, and from the disposal of solids such as tank bottoms and drilling fluids, as well as truck and frac tank washouts.

· Our liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada, and which provides natural gas liquids terminaling and storage services through its 19 owned terminals throughout the United States, its salt dome storage facility in Utah, and its leased storage and railcar transportation services through its fleet of leased railcars.

· Our retail propane segment, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 25 states and the District of Columbia.

· Our refined products and renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the 2% general partner interest and a 19.6% limited partner interest in TransMontaigne Partners L.P. (“TLP”), which conducts refined products terminaling, storage, and transportation operations. See Note 17 for a discussion of the sale of the 2% general partner interest in TLP.

Note 2—Significant Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include our accounts and those of our controlled subsidiaries. All significant 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 (see Note 4). We will include our proportionate share of assets, liabilities, and expenses related to this pipeline in our 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. Accordingly, the unaudited condensed consolidated financial statements exclude certain information and notes required by GAAP for complete annual consolidated financial statements. However, we believe that the disclosures made are adequate to make the information presented not misleading. The unaudited condensed consolidated financial statements include all adjustments that we consider necessary for a fair presentation of our consolidated financial position and results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed in this Quarterly Report. The unaudited condensed consolidated balance sheet at March 31, 2015 is derived from our audited consolidated financial statements for the fiscal year ended March 31, 2015 included in our Annual Report on Form 10-K (“Annual Report”).

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

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.

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, 2016.

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 condensed consolidated financial statements include determining the fair value of assets and liabilities acquired in business combinations , the collectability 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, among others. 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

We record our commodity derivative instruments and assets and liabilities acquired in business combinations at fair value. 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.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to a fair value measurement requires judgment, considering factors specific to the asset or liability.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

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. Several of our terminaling service agreements with throughput customers allow us to receive the product volume gained resulting from differences between the measurement of product volumes received and distributed at our terminaling facilities. Such differences are due to the inherent variances in measurement devices and methodology. We record revenues for the net proceeds from the sale of the product gained. 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 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 and nine months ended December 31, 2015 include $1.5 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.

Supplemental Cash Flow Information

Supplemental cash flow information is as follows for the periods indicated:

	Three Months Ended December 31,					Nine Months Ended December 31,
	2015			2014		2015		2014
	(in thousands)
Interest paid, exclusive of debt issuance costs and letter of credit fees	$	32,722		$	28,927	$	90,217	$	65,356
Income taxes paid (net of income tax refunds)	$	(2,838	)	$	303	$	1,778	$	2,549

Cash flows from settlements of commodity derivative instruments are classified as cash flows from investing activities in our condensed consolidated statements of cash flows, and adjustments to the fair value of commodity derivative instruments are included in operating activities.

Inventories

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

Inventories consist of the following at the dates indicated:

	December 31,		March 31,
	2015		2015
	(in thousands)
Crude oil	$	81,723	$	145,412
Natural gas liquids—
Propane	65,962		44,535
Butane	15,014		8,668
Other	11,300		3,874
Refined products—
Gasoline	112,131		128,092
Diesel	78,082		59,097
Renewables	39,388		44,668
Other	10,488		7,416
Total	$	414,088	$	441,762

Investments in Unconsolidated Entities

We own noncontrolling interests in certain entities. We account for these investments using the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on our condensed consolidated balance sheets; instead, our ownership interests are reported within investments in unconsolidated entities on our condensed consolidated balance sheets. Under the equity method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions paid, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the historical net book value of the net assets of the investee.

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

		Ownership	Date Acquired	December 31,	March 31,
Entity	Segment	Interest	or Formed	2015	2015
				(in thousands)
Glass Mountain (1)	Crude oil logistics	50.0%	December 2013	$181,479	$187,590
BOSTCO (2)	Refined products and renewables	42.5%	July 2014	236,922	238,146
Frontera (2)	Refined products and renewables	50.0%	July 2014	17,595	16,927
Water supply company	Water solutions	35.0%	June 2014	16,102	16,471
Water treatment and disposal facility	Water solutions	50.0%	August 2015	2,290	—
Ethanol production facility	Refined products and renewables	19.0%	December 2013	12,507	13,539
Retail propane company	Retail propane	50.0%	April 2015	664	—
Total				$467,559	$472,673

(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 $75.1 million at December 31, 2015. This difference relates primarily to goodwill and customer relationships.

(2) When we acquired TransMontaigne Inc. (“TransMontaigne”), we recorded the investments in Battleground Oil Specialty Terminal Company LLC (“BOSTCO”), which owns a refined products storage facility, and Frontera Brownsville LLC (“Frontera”) at fair value. On a combined basis, our investments in BOSTCO and Frontera exceed our proportionate share of the historical net book value of BOSTCO’s and Frontera’s net assets by $15.6 million at December 31, 2015. This difference relates primarily to goodwill.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

Other Noncurrent Assets

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

	December 31,		March 31,
	2015		2015
	(in thousands)
Loan receivable (1)	$	52,154	$	58,050
Linefill (2)	35,060		35,060
Other	18,872		19,727
Total	$	106,086	$	112,837

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

(2) Represents minimum volumes of crude oil we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At December 31, 2015, linefill consisted of 487,104 barrels of crude oil.

Accrued Expenses and Other Payables

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

	December 31,		March 31,
	2015		2015
	(in thousands)
Accrued compensation and benefits	$	41,425	$	52,078
Excise and other tax liabilities	49,217		43,847
Derivative liabilities	30,739		27,950
Accrued interest	19,730		23,065
Product exchange liabilities	21,317		15,480
Other	30,867		32,696
Total	$	193,295	$	195,116

Noncontrolling Interests

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

As part of our acquisition of TransMontaigne on July 1, 2014, we acquired a 2% general partner interest and a 19.7% limited partner interest in TLP. We attribute net earnings allocable to TLP’s limited partners to the controlling and noncontrolling interests based on the relative ownership interests in TLP. Earnings allocable to TLP’s limited partners are net of the earnings allocable to TLP’s general partner interest. The earnings allocable to TLP’s general partner interest include the distributions of cash attributable to the period to TLP’s general partner interest and incentive distribution rights, net of adjustments for TLP’s general partner’s proportionate share of undistributed earnings. Undistributed earnings are allocated to TLP’s limited partners and TLP’s general partner interest based on their ownership percentages of 98% and 2%, respectively. See Note 17 for a discussion of the sale of the 2% general partner interest in TLP.

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 no more than one year to obtain the information necessary to identify and measure the fair values of the

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

assets acquired and liabilities assumed in a business combination. As described in Note 5, certain 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.

Recent Accounting Pronouncements

In July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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, 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 April 2015, the FASB issued ASU No. 2015—03, “Simplifying the Presentation of Debt Issuance Costs.” The ASU requires that debt issuance costs (excluding costs associated with revolving debt arrangements) be presented in the balance sheet as a reduction to the carrying amount of the debt. We plan to adopt this ASU effective March 31, 2016, when we will begin presenting debt issuance costs as a reduction to long-term debt, rather than as an intangible asset. At December 31, 2015, intangible assets on our condensed consolidated balance sheet include $17.4 million of debt issuance costs associated with our senior notes that, upon adoption of this ASU, would be reclassified as a reduction to long-term debt. The ASU requires retrospective application for all prior periods presented. At March 31, 2015, intangible assets on our condensed consolidated balance sheet include $17.8 million of debt issuance costs associated with our senior notes that, upon adoption of this ASU, will be reclassified as a reduction to long-term debt.

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

Note 3—Income (Loss) Per Common Unit

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

	Three Months Ended December 31,						Nine Months Ended December 31,
	2015			2014			2015			2014
	(in thousands, except unit and per unit amounts)
Net income (loss) attributable to parent equity	$	23,481		$	(10,918	)	$	(45,963	)	$	(70,117	)
Less: Net income allocated to general partner (1)	(16,217		)	(11,783		)	(47,742		)	(32,220		)
Less: Net loss allocated to subordinated unitholders (2)	—			—			—			4,013
Net income (loss) attributable to common unitholders (basic)	7,264			(22,701		)	(93,705		)	(98,324		)
Effect of dilutive securities (restricted units)	(3,967		)	—			—			—
Net income (loss) attributable to common unitholders (diluted)	$	3,297		$	(22,701	)	$	(93,705	)	$	(98,324	)

Basic income (loss) per common unit	$	0.07		$	(0.26	)	$	(0.89	)	$	(1.17	)
Diluted income (loss) per common unit	$	0.03		$	(0.26	)	$	(0.89	)	$	(1.17	)

Basic weighted average common units outstanding	105,338,200			88,545,764			104,808,649			83,702,571
Diluted weighted average common units outstanding	106,194,547			88,545,764			104,808,649			83,702,571

(1) Net income allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights, which are described in Note 12.

(2) All outstanding subordinated units converted to common units in August 2014. Since the subordinated units did not share in the distribution of cash generated after June 30, 2014, we did not allocate any income or loss after that date to the subordinated unitholders. During the three months ended June 30, 2014, 5,919,346 subordinated units were outstanding and the loss per subordinated unit was $(0.68).

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

The diluted weighted average common units outstanding for the three months ended December 31, 2015 included 856,347 restricted units (as described in Note 12) that were considered dilutive for the period. For the nine months ended December 31, 2015 and the three months and nine months ended December 31, 2014, the restricted units were considered antidilutive.

Note 4—Grand Mesa Pipeline

In October 2014, we completed a successful open season in which we received the requisite support, in the form of ship-or-pay volume commitments from multiple shippers, to begin construction of Grand Mesa Pipeline, which was planned to originate in Colorado and terminate in Cushing, Oklahoma. In November 2015, we combined the Grand Mesa Pipeline project and entered into an agreement with Saddlehorn Pipeline Company, LLC (“Saddlehorn”), under which we acquired a 37.5% undivided interest in a crude oil pipeline currently under construction (the “Joint Pipeline”). The Joint Pipeline will have several points of origin in Colorado and will terminate in Cushing, Oklahoma. We will have the right to utilize 150,000 barrels per day of capacity on the Joint Pipeline. Operating costs will be allocated to us based on our proportionate ownership interest and throughput. We expect the Joint Pipeline to be operational beginning in the fourth quarter of calendar year 2016.

Through our undivided interest in the Joint Pipeline, Grand Mesa will have expanded capacity, sufficient to service our customer contracts at the same origin and termination points with the ability to accept additional volume commitments. We will retain ownership of our previously-acquired easements for the potential future development of transportation projects involving petroleum commodities other than crude oil and condensate. With the consent and participation of Saddlehorn, we and Saddlehorn may consider future opportunities using these easements for projects involving the transportation of crude oil and condensate.

We paid $125 million towards the construction of the pipeline during the three months ended December 31, 2015.

Prior to reaching the agreement with Saddlehorn, we purchased $87.4 million of pipe that we expected to use for the Grand Mesa Pipeline. During the three months ended December 31, 2015, we reclassified this pipe to assets held for sale. To determine the value of the pipe at December 31, 2015, we inquired of a third party manufacturer as to the current cost of similar pipe. Based on the information we received, the fair value of the pipe approximated our carrying value. To facilitate the sale of this pipe, we notified potential buyers at the end of December 2015 that we would be accepting bids for the pipe through February 15, 2016. Initial discussions held in January 2016 with potential buyers indicated to us that we would probably need to sell the pipe at an amount less than the carrying value as of December 31, 2015. Based on these indications, we expect to record a loss on the sale of these assets during the fourth quarter of fiscal year 2016. In addition, we reclassified $47.0 million of costs to acquire land, rights-of-way, and easements on the originally-planned Grand Mesa Pipeline route as intangible assets in our condensed consolidated balance sheet.

Note 5—Acquisitions

Year Ending March 31, 2016

Delaware Basin Water Solutions Facilities

On August 24, 2015, we acquired four saltwater disposal facilities and a 50% interest in an additional saltwater disposal facility in the Delaware Basin of the Permian Basin in Texas for $50.0 million of cash. We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in this business combination, and as a result, the estimates of fair value at December 31, 2015 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending June 30, 2016. The following table summarizes the preliminary estimates of the fair values of the assets acquired (and useful lives) and liabilities assumed (in thousands):

Property, plant and equipment:
Water treatment facilities and equipment (3—30 years)	$	18,650
Land	400
Goodwill	12,776
Intangible asset:
Customer relationships (6 years)	16,000
Investments in unconsolidated entities	2,290
Accrued expenses and other payables	(116		)
Fair value of net assets acquired	$	50,000

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

Partnership and the opportunity to use the acquired business as a platform for growth. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Water Solutions Facilities

We are party to a development agreement that requires us to purchase water solutions facilities developed by the other party to the agreement. During the nine months ended December 31, 2015, we purchased 12 water treatment and disposal facilities under this development agreement. We also purchased one additional water treatment and disposal facility in December 2015 from a different seller. On a combined basis, we paid $120.0 million of cash and issued 781,255 common units, valued at $18.1 million, in exchange for these facilities.

During the nine months ended December 31, 2015, we completed the acquisition accounting for six of these water treatment and disposal facilities. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these water treatment and disposal facilities:

Property, plant and equipment:
Water treatment facilities and equipment (3—30 years)	$	25,099
Buildings and leasehold improvements (7—30 years)	6,495
Land	1,070
Other (5 years)	32
Goodwill	43,252
Accrued expenses and other payables	(102		)
Other noncurrent liabilities	(174		)
Fair value of net assets acquired	$	75,672

We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed for the other seven water treatment and disposal facilities, and as a result, the estimates of fair value at December 31, 2015 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending September 30, 2016. The following table summarizes the preliminary estimates of the fair values of the assets acquired (and useful lives) and liabilities assumed (in thousands):

Property, plant and equipment:
Water treatment facilities and equipment (3—30 years)	$	32,776
Buildings and leasehold improvements (7—30 years)	4,802
Land	544
Other (5 years)	20
Goodwill	28,484
Accrued expenses and other payables	(4,000		)
Other noncurrent liabilities	(198		)
Fair value of net assets acquired	$	62,428

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

Retail Propane Businesses

During the nine months ended December 31, 2015, we acquired five retail propane businesses. On a combined basis, we paid $17.4 million of cash and issued 52,199 common units, valued at $1.0 million, in exchange for these assets and operations. The agreements for these acquisitions contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in these business combinations, and as a

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

result, the estimates of fair value at December 31, 2015 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending September 30, 2016.

Year Ended March 31, 2015

As described in Note 2, pursuant to GAAP, an entity is allowed no more than one year to obtain the information necessary to identify and measure the fair values of the assets acquired and liabilities assumed in a business combination. The changes we made during the nine months ended December 31, 2015 to the estimated acquisition date fair values of assets acquired and liabilities assumed in these business combinations are described below. We have not retrospectively adjusted previously issued financial statements for these changes, as we do not believe the changes are material.

Natural Gas Liquids Storage Facility

In February 2015, we acquired Sawtooth NGL Caverns, LLC (“Sawtooth”), which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets and entered into a construction agreement to expand the storage capacity of the facility. We paid $97.6 million of cash, net of cash acquired, and issued 7,396,973 common units, valued at $218.5 million, in exchange for these assets and operations. During the nine months ended December 31, 2015, we completed the acquisition accounting for this business combination. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for this acquisition:

				Estimated At
				March 31,
	Final			2015			Change
	(in thousands)
Accounts receivable—trade	$	42		$	42		$	—
Inventories		263			—			263
Prepaid expenses and other current assets	843			600			243
Property, plant and equipment:
Natural gas liquids terminal and storage assets (2—30 years)	61,130			62,205			(1,075		)
Vehicles and railcars (3—25 years)	78			75			3
Land	69			68			1
Other	17			32			(15		)
Construction in progress	19,525			19,525			—
Goodwill	183,096			151,853			31,243
Intangible assets:
Customer relationships (15 years)	61,500			85,000			(23,500		)
Non-compete agreements (10 years)	5,100			12,000			(6,900		)
Accounts payable—trade	(931		)	(931		)	—
Accrued expenses and other payables	(6,774		)	(6,511		)	(263		)
Advance payments received from customers	(1,015		)	(1,015		)	—
Other noncurrent liabilities	(6,817		)	(6,817		)	—
Fair value of net assets acquired	$	316,126		$	316,126		$	—

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

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

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. Since certain storage leases were at unfavorable terms relative to acquisition date market conditions, we recorded a liability of $12.8 million related to these leases in the acquisition accounting, a portion of which we recorded to accrued expenses and other payables and a portion of which we recorded to other noncurrent liabilities. We amortized $4.4 million of this balance as an increase to revenues during the nine months ended December 31, 2015. We will amortize the remainder of this liability over the terms of the leases. The following table summarizes the future amortization of this liability (in thousands):

Year Ending March 31,
2016 (three months)	$	1,452
2017	4,905
2018	1,306
2019	88

Bakken Water Solutions Facilities

On November 21, 2014, we acquired two saltwater disposal facilities in the Bakken shale play in North Dakota for $34.6 million of cash. During the six months ended September 30, 2015, we completed the acquisition accounting for these water treatment and disposal facilities. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these water treatment and disposal facilities:

				Estimated At
				March 31,
	Final			2015			Change
	(in thousands)
Property, plant and equipment:
Vehicles (10 years)	$	63		$	63		$	—
Water treatment facilities and equipment (3—30 years)	5,815			5,815			—
Buildings and leasehold improvements (7—30 years)	130			130			—
Land	100			100			—
Goodwill	4,421			6,560			(2,139		)
Intangible asset:
Customer relationships (7 years)	24,300			22,000			2,300
Other noncurrent assets	75			—			75
Other noncurrent liabilities	(304		)	(68		)	(236		)
Fair value of net assets acquired	$	34,600		$	34,600		$	—

TransMontaigne Inc.

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

limited partner interest in TLP, and assumed certain terminaling service agreements with TLP from an affiliate of the previous owner of TransMontaigne.

During the three months ended June 30, 2015, we completed the acquisition accounting for this business combination. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for this acquisition:

				Estimated At
				March 31,
	Final			2015			Change
	(in thousands)
Cash and cash equivalents	$	1,469		$	1,469		$	—
Accounts receivable—trade	199,366			197,829			1,537
Accounts receivable—affiliates	528			528			—
Inventories	373,870			373,870			—
Prepaid expenses and other current assets	15,110			15,001			109
Property, plant and equipment:
Refined products terminal assets and equipment (20 years)	415,317			399,323			15,994
Vehicles	1,696			1,698			(2		)
Crude oil tanks and related equipment (20 years)	1,085			1,058			27
Information technology equipment	7,253			7,253			—
Buildings and leasehold improvements (20 years)	15,323			14,770			553
Land	61,329			70,529			(9,200		)
Tank bottoms (indefinite life)	46,900			46,900			—
Other	15,536			15,534			2
Construction in progress	4,487			4,487			—
Goodwill	30,169			28,074			2,095
Intangible assets:
Customer relationships (15 years)	66,000			76,100			(10,100		)
Pipeline capacity rights (30 years)	87,618			87,618			—
Investments in unconsolidated entities	240,583			240,583			—
Other noncurrent assets	3,911			3,911			—
Accounts payable—trade	(113,103		)	(113,066		)	(37		)
Accounts payable—affiliates	(69		)	(69		)	—
Accrued expenses and other payables	(79,405		)	(78,427		)	(978		)
Advance payments received from customers	(1,919		)	(1,919		)	—
Long-term debt	(234,000		)	(234,000		)	—
Other noncurrent liabilities	(33,227		)	(33,227		)	—
Noncontrolling interests	(545,120		)	(545,120		)	—
Fair value of net assets acquired	$	580,707		$	580,707		$	—

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

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

The fair value of the noncontrolling interests was calculated by multiplying the closing price of TLP’s common units on the acquisition date by the number of TLP common units held by parties other than us, adjusted for a lack-of-control discount.

See Note 17 for a discussion of the sale of the 2% general partner interest in TLP.

Water Solutions Facilities

We are party to a development agreement that requires us to purchase water solutions facilities developed by the other party to the agreement. During the year ended March 31, 2015, we purchased 16 water treatment and disposal facilities under this development agreement. We also purchased a 75% interest in one additional water treatment and disposal facility in July 2014 from a different seller. On a combined basis, we paid $ 190.0 million of cash and issued 1,322,032 common units, valued at $37.8 million, in exchange for these 17 facilities.

During the nine months ended December 31, 2015, we completed the acquisition accounting for all of these water treatment and disposal facilities. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these water treatment and disposal facilities:

				Estimated At
				March 31,
	Final			2015			Change
	(in thousands)
Accounts receivable—trade	$	939		$	939		$	—
Inventories	253			253			—
Prepaid expenses and other current assets	62			62			—
Property, plant and equipment:
Water treatment facilities and equipment (3–30 years)	79,982			79,706			276
Buildings and leasehold improvements (7–30 years)	10,690			10,250			440
Land	3,127			3,109			18
Other (5 years)	132			129			3
Goodwill	132,033			132,770			(737		)
Intangible asset:
Customer relationships (4 years)	10,000			10,000			—
Other noncurrent assets	50			50			—
Accounts payable—trade	(58		)	(58		)	—
Accrued expenses and other payables	(3,092		)	(3,092		)	—
Other noncurrent liabilities	(582		)	(582		)	—
Noncontrolling interest	(5,775		)	(5,775		)	—
Fair value of net assets acquired	$	227,761		$	227,761		$	—

Retail Propane Businesses

During the year ended March 31, 2015, we acquired eight retail propane businesses. On a combined basis, we paid $39.1 million of cash and issued 132,100 common units, valued at $3.7 million, in exchange for these assets and operations.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

During the six months ended September 30, 2015, we completed the acquisition accounting for all of these business combinations. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these acquisitions:

				Estimated At
				March 31,
	Final			2015			Change
	(in thousands)
Accounts receivable—trade	$	2,237		$	2,237		$	—
Inventories	771			771			—
Prepaid expenses and other current assets	110			110			—
Property, plant and equipment:
Retail propane equipment (15–20 years)	13,177			13,177			—
Vehicles and railcars (5–7 years)	2,332			2,332			—
Buildings and leasehold improvements (30 years)	534			784			(250		)
Land	505			655			(150		)
Other (5–7 years)	118			116			2
Goodwill	8,097			8,097			—
Intangible assets:
Customer relationships (10–15 years)	17,563			17,563			—
Non-compete agreements (5–7 years)	500			500			—
Trade names (3–12 years)	950			950			—
Accounts payable—trade	(1,523		)	(1,921		)	398
Advance payments received from customers	(1,750		)	(1,750		)	—
Current maturities of long-term debt	(78		)	(78		)	—
Long-term debt, net of current maturities	(760		)	(760		)	—
Fair value of net assets acquired	$	42,783		$	42,783		$	—

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

Note 6—Property, Plant and Equipment

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

	Estimated	December 31,			March 31,
Description	Useful Lives	2015			2015
		(in thousands)
Natural gas liquids terminal and storage assets	2–30 years	$	125,579		$	132,851
Refined products terminal assets and equipment	20 years	444,087			403,609
Retail propane equipment	2–30 years	195,604			181,140
Vehicles and railcars	3–25 years	192,394			180,679
Water treatment facilities and equipment	3–30 years	453,345			317,317
Crude oil tanks and related equipment	2–40 years	131,159			109,909
Barges and towboats	5–40 years	79,113			59,848
Information technology equipment	3–7 years	42,082			34,915
Buildings and leasehold improvements	3–40 years	125,580			98,989
Land		104,059			107,098
Tank bottoms		63,566			62,656
Other	3–30 years	25,851			34,415
Construction in progress		295,739			96,922
		2,278,158			1,820,348
Accumulated depreciation		(305,233		)	(202,959		)
Net property, plant and equipment		$	1,972,925		$	1,617,389

The following table summarizes depreciation expense for the periods indicated:

Three Months Ended December 31,				Nine Months Ended December 31,
2015		2014		2015		2014
(in thousands)
$	35,443	$	29,723	$	105,707	$	76,593

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. The following table summarizes the tank bottoms included in the table above at the dates indicated:

	December 31, 2015			March 31, 2015
	Volume			Volume
Product	(in barrels)	Value		(in barrels)	Value
	(in thousands)
Gasoline	230	$	26,906	219	$	25,710
Crude oil	231	19,349		184	16,835
Diesel	113	13,697		124	15,153
Renewables	28	2,906		41	4,220
Other	12	708		12	738
Total		$	63,566		$	62,656

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

Note 7—Goodwill

The following table summarizes changes in goodwill by segment for the nine months ended December 31, 2015:

										Refined
	Crude Oil		Water					Retail		Products and
	Logistics		Solutions			Liquids		Propane		Renewables		Total
	(in thousands)
Balances at March 31, 2015	$	579,846	$	401,656		$	234,803	$	122,382	$	64,074	$	1,402,761
Revisions to acquisition accounting (Note 5)	—		(2,876		)	31,243		—		2,095		30,462
Acquisitions (Note 5)	—		84,512			—		4,909		—		89,421
Balances at December 31, 2015	$	579,846	$	483,292		$	266,046	$	127,291	$	66,169	$	1,522,644

Note 8—Intangible Assets

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

		December 31, 2015				March 31, 2015
	Estimated	Gross Carrying		Accumulated		Gross Carrying		Accumulated
Description	Useful Lives	Amount		Amortization		Amount		Amortization
		(in thousands)
Amortizable—
Customer relationships	3–20 years	$	910,618	$	220,422	$	921,418	$	159,215
Pipeline capacity rights	30 years	119,636		5,562		119,636		2,571
Water facility development agreement	5 years	14,000		7,000		14,000		4,900
Executory contracts and other agreements	2–10 years	23,920		20,471		23,920		18,387
Non-compete agreements	2–10 years	20,253		13,152		26,662		10,408
Trade names	2–12 years	15,439		11,610		15,439		7,569
Debt issuance costs	1–10 years	64,849		27,674		55,165		17,467
Total amortizable		1,168,715		305,891		1,176,240		220,517
Non-amortizable—
Customer commitments		310,000		—		310,000		—
Rights-of-way and easements (1)		46,996		—		—		—
Trade names		22,620		—		22,620		—
Total non-amortizable		379,616		—		332,620		—
Total		$	1,548,331	$	305,891	$	1,508,860	$	220,517

(1) As described in Note 4, we acquired land, rights-of-way, and easements along a planned pipeline route. We later acquired an undivided interest in a different crude oil pipeline with the same origin and destination points as those of our originally-planned route. We will retain the land, rights-of-way, and easements along the originally-planned route for potential future development.

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

Amortization expense is as follows for the periods indicated:

	Three Months Ended December 31,				Nine Months Ended December 31,
Recorded In	2015		2014		2015		2014
	(in thousands)
Depreciation and amortization	$	23,737	$	20,612	$	70,065	$	63,216
Cost of sales	1,701		1,818		5,102		5,939
Interest expense	5,649		2,451		10,207		6,480
Total	$	31,087	$	24,881	$	85,374	$	75,635

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

Year Ending March 31,
2016 (three months)	$	26,679
2017	103,418
2018	99,320
2019	89,360
2020	81,980
Thereafter	462,067
Total	$	862,824

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

Note 9—Long-Term Debt

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

	December 31,		March 31,
	2015		2015
	(in thousands)
Revolving credit facility—
Expansion capital borrowings	$	1,317,000	$	702,500
Working capital borrowings	603,500		688,000
5.125% Notes due 2019	400,000		400,000
6.875% Notes due 2021	450,000		450,000
6.650% Notes due 2022	250,000		250,000
TLP credit facility	248,000		250,000
Other long-term debt	62,592		9,271
	3,331,092		2,749,771
Less: Current maturities	7,600		4,472
Long-term debt	$	3,323,492	$	2,745,299

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, 2015, our Revolving Credit Facility had a total capacity of $2.474 billion. Our Revolving Credit Facility has an “accordion” feature that allows us to increase the capacity by $150.0 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 $1.436 billion for cash borrowings at December 31, 2015. At that date, we had outstanding borrowings of $1.317 billion 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, 2015. At that date, we had outstanding borrowings of $603.5 million and outstanding letters of credit of $117.1 million on the Working Capital Facility. Amounts outstanding for letters of credit are not recorded as long-term debt on our 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 mature 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 1.50% per year or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per year. The applicable margin is determined based on our consolidated leverage ratio (as defined in the Credit Agreement). At December 31, 2015, the borrowings under the Credit Agreement were LIBOR borrowings with an interest rate at December 31, 2015 of 2.68%, calculated as the LIBOR rate of 0.43% plus a margin of 2.25%. At December 31, 2015, 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 Credit Agreement is secured by substantially all of our assets. In December 2015, we entered into an agreement with the banks to increase our maximum leverage ratio to 4.50 to 1 at any quarter end. The leverage coverage ratio in our Credit Agreement excludes TLP’s debt. At December 31, 2015, our leverage ratio was approximately 4.0 to 1. The Credit Agreement also specifies that our interest coverage ratio (as defined in the Credit Agreement) cannot be less than 2.75 to 1 at any quarter end. At December 31, 2015, our interest coverage ratio was approximately 5.6 to 1.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.

At December 31, 2015, 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”). 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.

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2019 Notes, and the obligations under the 2019 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The indenture governing the 2019 Notes contains various customary covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. 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.

At December 31, 2015, 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”). 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.

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2021 Notes, and the obligations under the 2021 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The indenture governing the 2021 Notes contains various customary covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. 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.

At December 31, 2015, 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 “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. The 2022 Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create or permit certain liens, (iv) create or permit restrictions on the ability of certain of our subsidiaries to pay dividends or make other distributions to us, (v) enter into transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate , merge, or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains similar leverage ratio and interest coverage ratio requirements to those of our Credit Agreement described above. In December 2015, we amended the Note Purchase Agreement to change the covenants to mirror the changes made to the covenants in our Credit Agreement. In addition, we agreed to pay an additional 0.5% per year in interest if our leverage ratio exceeds 4.25 to 1.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

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

At December 31, 2015, we were in compliance with the covenants under the Note Purchase Agreement.

TLP Credit Facility

TLP is party to a credit agreement with a syndicate of banks that provides for a revolving credit facility (the “TLP Credit Facility”). The TLP Credit Facility provides for a maximum borrowing line of credit equal to the lesser of (i) $400 million or (ii) 4.75 times Consolidated EBITDA (as defined in the TLP Credit Facility). The terms of the TLP Credit Facility include covenants that restrict TLP’s ability to make cash distributions, acquisitions and investments, including investments in joint ventures. TLP may make distributions of cash to the extent of TLP’s “available cash” (as defined in TLP’s partnership agreement). TLP may make acquisitions and investments that meet the definition of “permitted acquisitions,” “other investments” which may not exceed 5% of “consolidated net tangible assets,” and additional future “permitted JV investments” up to $125 million, which may include additional investments in BOSTCO. The commitments under the TLP Credit Facility mature on July 31, 2018.

TLP may elect to have loans under the TLP Credit Facility bear interest at either (i) a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLP also pays commitment fees on any unused capacity, ranging from 0.375% to 0.5% per year, depending on the total leverage ratio then in effect. For the three months ended December 31, 2015, the weighted-average interest rate on borrowings under the TLP Credit Facility was approximately 2.9%. TLP’s obligations under the TLP Credit Facility are secured by a first priority security interest in favor of the lenders in the majority of TLP’s assets, including TLP’s investments in unconsolidated entities. At December 31, 2015, TLP had outstanding borrowings under the TLP Credit Facility of $248.0 million and no outstanding letters of credit.

The TLP Credit Facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the TLP Credit Facility are (i) a total leverage ratio test (not to exceed 4.75 times), (ii) a senior secured leverage ratio test (not to exceed 3.75 times) if TLP issues senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times). These financial covenants are based on “Consolidated EBITDA” (as defined in the TLP Credit Facility). The TLP Credit Facility is non-recourse to the Partnership. At December 31, 2015, TLP was in compliance with the covenants under the TLP Credit Facility.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

The following table summarizes our basis in the assets and liabilities of TLP at December 31, 2015, inclusive of the impact of our acquisition accounting for the business combination with TransMontaigne (in thousands):

Cash and cash equivalents	$	681
Accounts receivable—trade	5,974
Accounts receivable—affiliates	515
Inventories	1,411
Prepaid expenses and other current assets	999
Property, plant and equipment, net	474,331
Goodwill	30,169
Intangible assets, net	60,409
Investments in unconsolidated entities	254,516
Other noncurrent assets	674
Accounts payable—trade	(7,895		)
Accounts payable—affiliates	(153		)
Net intercompany payable	(1,632		)
Accrued expenses and other payables	(8,584		)
Advanced payments received from customers	(151		)
Long-term debt	(248,000		)
Other noncurrent liabilities	(2,731		)
Net assets	$	560,533

Other Long-Term Debt

We have executed various noninterest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also have certain notes payable related to equipment financing. These instruments have a combined principal balance of $62.6 million at December 31, 2015, and the interest rates on these instruments range from 2.06% to 8.60% per year.

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at December 31, 2015:

	Revolving								TLP		Other
	Credit		2019		2021		2022		Credit		Long-Term
Year Ending March 31,	Facility		Notes		Notes		Notes		Facility		Debt		Total
	(in thousands)
2016 (three months)	$	—	$	—	$	—	$	—	$	—	$	1,016	$	1,016
2017	—		—		—		—		—		7,263		7,263
2018	—		—		—		25,000		—		7,056		32,056
2019	1,920,500		—		—		50,000		248,000		6,581		2,225,081
2020	—		400,000		—		50,000		—		5,959		455,959
Thereafter	—		—		450,000		125,000		—		34,717		609,717
Total	$	1,920,500	$	400,000	$	450,000	$	250,000	$	248,000	$	62,592	$	3,331,092

Note 10—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 proportionate 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.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

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 2012 to 2015 generally remain subject to examination by federal, state, and Canadian tax authorities. We use the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.

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 condensed consolidated financial statements at December 31, 2015 or March 31, 2015.

Note 11—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 condensed consolidated balance sheet at December 31, 2015 includes a liability of $3.6 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.

The U.S. Environmental Protection Agency (“EPA”) has informed NGL Crude Logistics, LLC (“NGL Crude”; formerly known as Gavilon Energy prior to its acquisition by us in December 2013) of alleged violations in 2011 by Gavilon Energy of the Clean Air Act’s renewable fuel standards regulations. The EPA’s allegations relate to transactions between Gavilon Energy and one of its suppliers and the generation of biodiesel renewable identification numbers sold by such supplier to Gavilon Energy in 2011. We have vigorously denied the allegations. In an effort to resolve this matter, the parties have recently commenced settlement negotiations, which are ongoing.

At this time, we are unable to ascertain whether the settlement discussions will produce a resolution satisfactory to us or whether the EPA will seek resolution of the matter through an enforcement action. As a result, we are also unable to determine the likely terms of any resolution or their significance to us. Although we believe we have legal defenses, it is reasonably possible that we may agree to pay the EPA some amount to settle the matter.

Asset Retirement Obligations

Our condensed consolidated balance sheet at December 31, 2015 includes a liability of $5.0 million related to asset retirement obligations, which is reported within other noncurrent liabilities. This liability is related to 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.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

regulations, after considering the estimated lives of our facilities, is not material to our consolidated financial position or results of operations.

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, 2015 (in thousands):

Year Ending March 31,
2016 (three months)	$	28,264
2017	100,606
2018	85,570
2019	61,645
2020	52,043
Thereafter	115,311
Total	$	443,439

The following table summarizes rental expense for operating leases for the periods indicated:

Three Months Ended December 31,				Nine Months Ended December 31,
2015		2014		2015		2014
(in thousands)
$	25,548	$	36,767	$	92,623	$	91,400

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, 2015 (in thousands):

Year Ending March 31,
2016 (three months)	$	14,156
2017	56,684
2018	56,770
2019	55,978
2020	46,146
Thereafter	90,972
Total	$	320,706

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

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, 2015:

	Volume	Value
	(in thousands)
Purchase commitments:
Natural gas liquids fixed-price (gallons)	25,653	$	14,506
Natural gas liquids index-price (gallons)	406,147	167,396
Crude oil fixed-price (barrels)	1,075	46,195
Crude oil index-price (barrels)	21,371	546,299
Sale commitments:
Natural gas liquids fixed-price (gallons)	146,488	102,610
Natural gas liquids index-price (gallons)	267,468	175,650
Crude oil fixed-price (barrels)	2,093	95,902
Crude oil index-price (barrels)	21,331	658,906

We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs. Contracts in the table above may have offsetting derivative contracts (see Note 13) 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 condensed consolidated balance sheet and are not included in the table above. These contracts are included in the derivative disclosures in Note 13, and represent $41.3 million of our prepaid expenses and other current assets and $30.0 million of our accrued expenses and other payables at December 31, 2015.

Note 12—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 is not required to make any additional capital contributions or to guarantee or pay any of our debts and obligations.

Common Units Issued in Business Combinations

During the nine months ended December 31, 2015, we issued 833,454 common units, valued at $19.1 million, as consideration for certain business combinations .

Common Unit Repurchase Program

On September 10, 2015, the Board of Directors of our general partner authorized a common unit repurchase program, under which we may repurchase up to $45 million of our outstanding common units through March 31, 2016. We may repurchase common units from time to time in the open market or in other privately negotiated transactions. The common unit repurchase program authorization does not obligate us to repurchase any dollar amount or number of our common units. During the nine months ended December 31, 2015, we repurchased 398,141 common units for an aggregate price of $7.7 million.

Our Distribution Policy

Our general partner has adopted a cash distribution policy that requires us to pay a quarterly distribution to unitholders as of the record date to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner and its affiliates, referred to as “available cash.” The general partner will also

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

receive, in addition to distributions on its 0.1% general partner interest, additional distributions based on the level of distributions to the limited partners. These distributions are referred to as “incentive distributions” or “IDRs.” Our general partner currently holds the IDRs, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

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

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

In January 2016, we declared a distribution of $0.64 per common unit, to be paid on February 15, 2016 to unitholders of record on February 3, 2016. This distribution is expected to be $83.6 million, including amounts to be paid on common and general partner notional units as well as an incentive distribution.

TLP’s Distribution Policy

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

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

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

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

In January 2016, TLP declared a distribution of $0.67 per common unit, which was paid on February 8, 2016. We received a total of $4.1 million from this distribution on our general partner interest, IDRs, and limited partner interest. The noncontrolling interest owners received a total of $8.7 million from this distribution.

Equity-Based Incentive Compensation

Our general partner has adopted a long-term incentive plant (“LTIP”), which allows for the issuance of equity-based incentive compensation. Awards granted under the LTIP include restricted units that vest contingent on the continued service of the recipients through the vesting date (the “Service Awards”). Awards also include restricted units that are contingent upon both 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”). The awards may also vest in the event of a change of control, at the discretion of the board of directors. No distributions accrue to or are paid on the restricted units during the vesting period.

The following table summarizes the Service Award activity during the nine months ended December 31, 2015:

Unvested Service Award units at March 31, 2015	2,260,400
Units granted	787,562
Units vested and issued	(833,029	)
Units withheld for employee taxes	(455,651	)
Units forfeited	(91,000	)
Unvested Service Award units at December 31, 2015	1,668,282

The following table summarizes the scheduled vesting of our unvested Service Award units:

Year Ending March 31,		Number of Units
2016 (three months)		20,000
2017		807,141
2018		734,141
Thereafter		107,000
Unvested Service Award units at December 31, 2015		1,668,282

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

We record the expense for the first tranche of each Service Award on a straight-line basis over the period beginning with the grant date of the awards and ending with the vesting date of the tranche. We record the expense for succeeding tranches over the period beginning with the vesting date of the previous tranche and ending with the vesting date of the tranche. At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using the closing price of our common units on the New York Stock Exchange on the balance sheet date, adjusted to reflect the fact that the holders of the unvested units are not entitled to distributions during the vesting period. We estimate the impact of the lack of distribution rights during the vesting period using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth. The following table summarizes expense related to Service Award units for the periods indicated:

Three Months Ended December 31,				Nine Months Ended December 31,
2015		2014		2015		2014
(in thousands)
$	403	$	1,600	$	33,765	$	23,300

Of the restricted units granted and vested during the nine months ended December 31, 2015, 465,239 units were granted as a bonus for performance during the fiscal year ended March 31, 2015. We accrued expense of $10.0 million during the fiscal year ended March 31, 2015 as an estimate of the value of such bonus units that would be granted. During the nine months ended December 31, 2015, we recorded an additional $1.8 million of expense to true-up the estimate to the $11.8 million of actual expense associated with these bonuses. Since the units were not formally granted until July 2015, the full $11.8 million value is reflected in the expense during the nine months ended December 31, 2015 in the table above.

The following table summarizes the estimated future expense we expect to record on the unvested Service Award units at December 31, 2015 (in thousands), after taking into consideration estimated forfeitures of approximately 164,000 units. For purposes of this calculation, we used the closing price of our common units on December 31, 2015, which was $11.04.

Year Ending March 31,
2016 (three months)	$	2,413
2017	7,634
2018	2,435
Thereafter	588
Total	$	13,070

The following table is a rollforward of the liability related to the Service Award units, which is reported within accrued expenses and other payables in our condensed consolidated balance sheets (in thousands):

Balance at March 31, 2015	$	6,154
Expense recorded	33,765
Value of units vested and issued	(23,502		)
Taxes paid on behalf of participants	(12,883		)
Balance at December 31, 2015	$	3,534

The weighted-average fair value of the Service Award units at December 31, 2015 was $8.24 per common unit, which was calculated as the closing price of our common units on December 31, 2015, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

During April 2015, our general partner granted Performance Award units to certain employees. The following table summarizes the maximum number of units that could vest on these Performance Awards for each vesting tranche, taking into consideration any Performance Awards that have been forfeited since the grant date:

		Maximum Performance
Vesting Date of Tranche		Award Units
July 1, 2016		665,382
July 1, 2017		657,382
Total		1,322,764

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. Performance will be measured over the following periods:

Vesting Date of Tranche		Performance Period for Tranche
July 1, 2016		July 1, 2013 through June 30, 2016
July 1, 2017		July 1, 2014 through June 30, 2017

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:

Percentage of Entities in the	Percentage of Maximum
Index that NGL Outperforms	Performance Award Units to Vest
Less than 50%	0	%
50%–75%	25%–50	%
75%–90%	50%–100	%
Greater than 90%	100	%

The April 2015 Performance Award grants included a tranche that vested on July 1, 2015. During the July 1, 2012 through June 30, 2015 performance period, the return on our common units exceeded the return on 83% of our peer companies in the Index. As a result, the July 1, 2015 tranche of the Performance Awards vested at 76% of the maximum number of awards, and 530,564 common units vested on July 1, 2015. Of these units, recipients elected for us to withhold 210,137 common units for employee taxes, valued at $6.4 million. We issued the remaining 320,427 common units, valued at $9.7 million, on July 1, 2015.

The following table summarizes the estimated fair value for each unvested tranche at December 31, 2015 (without consideration of estimated forfeitures):

	Fair Value of
Vesting Date of Tranche	Unvested Awards
	(in thousands)
July 1, 2016	$	266
July 1, 2017	303
Total	$	569

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

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. At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using a Monte Carlo simulation. The following table summarizes the expense (benefit) recorded for each vesting tranche during the periods indicated:

	Three Months Ended
Vesting Date of Tranche	June 30, 2015		September 30, 2015			December 31, 2015			Total
	(in thousands)
July 1, 2015	$	15,469	$	609		$	—		$	16,078
July 1, 2016	1,720		(220		)	(1,352		)	148
July 1, 2017	602		(60		)	(453		)	89
Total	$	17,791	$	329		$	(1,805	)	$	16,315

The following table summarizes the estimated future expense we expect to record on the unvested Performance Award units at December 31, 2015 (in thousands), after taking into consideration estimated forfeitures. For purposes of this calculation, we used the December 31, 2015 fair value of the Performance Awards.

Year Ending March 31,
2016 (three months)	$	84
2017	180
2018	32
Total	$	296

The following table is a rollforward of the liability related to the Performance Award units, which is reported within accrued expenses and other payables in our condensed consolidated balance sheets (in thousands):

Balance at March 31, 2015	$	—
Expense recorded	16,315
Value of units vested and issued	(9,658		)
Taxes paid on behalf of participants	(6,420		)
Balance at December 31, 2015	$	237

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, 2015, approximately 5.3 million common units remain available for issuance under the LTIP.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

Note 13—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 condensed consolidated balance sheet at the dates indicated:

	December 31, 2015						March 31, 2015
	Derivative			Derivative			Derivative			Derivative
	Assets			Liabilities			Assets			Liabilities
	(in thousands)
Level 1 measurements	$	65,865		$	(2,965	)	$	83,779		$	(3,969	)
Level 2 measurements	44,843			(31,198		)	34,963			(28,764		)
	110,708			(34,163		)	118,742			(32,733		)

Netting of counterparty contracts (1)	(1,215		)	1,215			(1,804		)	1,804
Net cash collateral provided (held)	(41,573		)	2,209			(56,660		)	2,979
Commodity derivatives in condensed consolidated balance sheet	$	67,920		$	(30,739	)	$	60,278		$	(27,950	)

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

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

	December 31,			March 31,
	2015			2015
	(in thousands)
Prepaid expenses and other current assets	$	67,920		$	60,278
Accrued expenses and other payables	(30,739		)	(27,950		)
Net commodity derivative asset	$	37,181		$	32,328

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

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

		Net Long (Short)		Fair Value
		Notional		of
		Units		Net Assets
Contracts	Settlement Period	(Barrels)		(Liabilities)
		(in thousands)
At December 31, 2015—
Cross-commodity (1)	January 2016–March 2017	284		$	1,684
Crude oil fixed-price (2)	January 2016–March 2016	(1,048	)	3,603
Propane fixed-price (2)	January 2016–December 2017	425		(2,265		)
Refined products fixed-price (2)	January 2016–February 2017	(6,520	)	69,448
Other	January 2016–December 2016	(220	)	4,075
				76,545
Net cash collateral held				(39,364		)
Net commodity derivatives in condensed consolidated balance sheet				$	37,181

At March 31, 2015—
Cross-commodity (1)	April 2015–March 2016	98		$	(105	)
Crude oil fixed-price (2)	April 2015–June 2015	(1,113	)	(171		)
Crude oil index-price (3)	April 2015–July 2015	751		1,835
Propane fixed-price (2)	April 2015–December 2016	193		(2,842		)
Refined products fixed-price (2)	April 2015–December 2015	(3,005	)	84,996
Other	April 2015–December 2015			2,296
				86,009
Net cash collateral held				(53,681		)
Net commodity derivatives in condensed consolidated balance sheet				$	32,328

(1) Cross-commodity—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) Commodity fixed-price—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.

(3) Commodity index-price—We may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different indices. These indices may vary in the commodity grade or location, or in the timing of delivery within a given month. These contracts are derivatives we have entered into as an economic hedge against the risk of one index moving relative to another index.

The following table summarizes the net gains recorded from our commodity derivatives to cost of sales for the periods indicated:

Three Months Ended December 31,				Nine Months Ended December 31,
2015		2014		2015		2014
(in thousands)
$	52,535	$	202,496	$	97,069	$	240,992

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

Credit Risk

We have credit policies that we believe minimize our overall credit risk, including an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances, and the use of industry standard master netting agreements, which allow for offsetting counterparty receivable and payable balances for certain transactions. At December 31, 2015, 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 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, 2015 (in thousands):

5.125% Notes due 2019	$	328,000
6.875% Notes due 2021	337,500
6.650% Notes due 2022	200,500

For the 2019 Notes and the 2021 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 14—Segments

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

Our liquids and retail propane segments each consist of two divisions, which are organized based on the location of the operations. The “corporate and other” category consists primarily of certain corporate expenses that are not allocated to the reportable segments.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

	Three Months Ended December 31,						Nine Months Ended December 31,
	2015			2014			2015			2014
	(in thousands)
Revenues:
Crude oil logistics—
Crude oil sales	$	508,863		$	1,689,106		$	2,818,752		$	5,727,779
Crude oil transportation and other	12,423			12,143			44,118			33,727
Water solutions—
Service fees	35,138			30,870			107,079			72,809
Recovered hydrocarbons	8,414			19,355			34,978			66,704
Water transportation	—			16			—			10,761
Other revenues	1,886			—			5,168			—
Liquids—
Propane sales	188,930			396,248			393,442			859,984
Other product sales	180,620			329,943			488,967			925,018
Other revenues	8,161			8,674			27,531			20,256
Retail propane—
Propane sales	68,880			99,859			148,184			200,437
Distillate sales	19,133			29,102			39,758			59,327
Other revenues	12,132			10,804			29,856			26,261
Refined products and renewables—
Refined products sales	1,532,928			1,831,243			4,946,136			5,283,855
Renewables sales	101,414			126,812			300,756			374,911
Service fees	32,381			25,993			89,193			49,999
Corporate and other	—			(1,281		)	—			1,513
Elimination of intersegment sales	(26,297		)	(56,741		)	(57,248		)	(132,055		)
Total revenues	$	2,685,006		$	4,552,146		$	9,416,670		$	13,581,286

Depreciation and Amortization:
Crude oil logistics	$	10,041		$	10,630		$	30,096		$	29,601
Water solutions	23,644			17,807			66,906			52,472
Liquids	3,537			2,838			11,286			9,423
Retail propane	9,096			7,949			26,711			23,204
Refined products and renewables	11,493			9,788			36,820			22,549
Corporate and other	1,369			1,323			3,953			2,560
Total depreciation and amortization	$	59,180		$	50,335		$	175,772		$	139,809

Operating Income (Loss):
Crude oil logistics	$	804		$	(26,814	)	$	12,689		$	(25,313	)
Water solutions	(5,778		)	34,505			(8,645		)	48,390
Liquids	32,921			(14,048		)	52,820			(4,032		)
Retail propane	14,450			21,477			11,985			16,829
Refined products and renewables	31,702			28,958			59,478			36,525
Corporate and other	(12,919		)	(25,999		)	(81,630		)	(67,105		)
Total operating income	$	61,180		$	18,079		$	46,697		$	5,294

(1) During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues to the categories shown in the table above. These changes did not impact total revenues. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

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

	Three Months Ended December 31,				Nine Months Ended December 31,
	2015		2014		2015		2014
	(in thousands)
Additions to property, plant and equipment:
Crude oil logistics	$	214,114	$	16,517	$	321,137	$	97,930
Water solutions	55,517		69,137		172,537		117,209
Liquids	5,824		1,096		41,888		4,166
Retail propane	9,716		12,097		29,359		24,508
Refined products and renewables	5,416		21,330		28,699		533,611
Corporate and other	11,655		616		12,824		3,878
Total	$	302,242	$	120,793	$	606,444	$	781,302

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

	December 31,		March 31,
	2015		2015
	(in thousands)
Long-lived assets, net:
Crude oil logistics	$	1,524,723	$	1,327,538
Water solutions	1,323,828		1,119,794
Liquids	564,783		534,560
Retail propane	479,240		467,652
Refined products and renewables	787,798		808,757
Corporate and other	57,637		50,192
Total	$	4,738,009	$	4,308,493

Total assets:
Crude oil logistics	$	2,198,205	$	2,337,188
Water solutions	1,413,274		1,185,929
Liquids	761,916		713,547
Retail propane	540,268		542,476
Refined products and renewables	1,512,911		1,668,836
Corporate and other	137,897		99,525
Total	$	6,564,471	$	6,547,501

Note 15 —Goodwill Impairment

We test goodwill for impairment on January 1 of each year, or more often if circumstances warrant. Crude oil prices began declining in July 2014 and continued to decline during calendar year 2015. Low crude oil prices have had an unfavorable impact on our water solutions business, as the volume of water we process is driven in part by the level of crude oil production, and the lower crude oil prices have given producers less incentive to expand production. In addition, a portion of the revenues of our water solutions business are generated from the sale of crude oil that we recover in the process of treating the wastewater, and low crude oil prices have had an adverse impact on these revenues.

Due to the decline in crude oil prices and the crude oil production, we tested the goodwill within our water solutions business for impairment as of December 31, 2015. We calculated fair value for our water solutions business by discounting the forecasted cash flows. Significant inputs to the valuation of the water solutions business includes estimates of (i) future cash flows, including revenues, expenses and capital expenditures, (ii) timing of cash flow, (iii) useful lives of the assets, (iv) forward crude oil prices, adjusted for estimated location differential and (v) a discount rate. Our calculation of estimated fair value exceeded the carrying value of our water solutions business. Due to the continuing volatility within the crude oil market we believe that it is reasonably possible that our estimate of fair value could change and result in us impairing a portion of the goodwill for our water solutions business. We plan to review our assumptions and inputs used in our calculation during the fourth quarter of fiscal year 2016.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

Note 16—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 condensed consolidated statements of operations. We also lease crude oil storage from SemGroup.

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

Certain members of our management and members of their families 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, 2015, $29.5 million of these transactions were capital expenditures and were recorded as increases to property, plant and equipment.

The following table summarizes these related party transactions:

	Three Months Ended December 31,				Nine Months Ended December 31,
	2015		2014		2015		2014
	(in thousands)
Sales to SemGroup	$	67	$	21,781	$	42,098	$	85,364
Purchases from SemGroup	5,052		31,247		50,355		116,931
Sales to equity method investees	1,676		2,382		4,762		11,512
Purchases from equity method investees	27,153		44,580		82,917		115,546
Sales to entities affiliated with management	91		186		289		2,040
Purchases from entities affiliated with management	6,709		10,446		30,103		17,430

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

	December 31,		March 31,
	2015		2015
	(in thousands)
Receivables from SemGroup	$	3,091	$	13,443
Receivables from equity method investees	693		652
Receivables from entities affiliated with management	28		3,103
Total	$	3,812	$	17,198

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

	December 31,		March 31,
	2015		2015
	(in thousands)
Payables to SemGroup	$	5,101	$	11,546
Payables to equity method investees	3,453		6,788
Payables to entities affiliated with management	2,488		7,460
Total	$	11,042	$	25,794

We also have a loan receivable of $23.3 million at December 31, 2015 from one of our equity method investees. During the three months ended December 31, 2015, we received a loan payment of $0.5 million from our investee in accordance with the loan agreement. The investee makes loan payments from time to time in accordance with the loan agreement and is required to make monthly principal payments beginning on June 1, 2018 with the remaining principal balance due on May 31, 2020.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

Note 17 —Subsequent Events

Water Pipeline Company

On January 7, 2016, we paid cash of $12.3 million in exchange for a 57.125% interest in an existing produced water pipeline company operating in the Delaware Basin portion of West Texas.

Sale of General Partner Interest in TLP

On February 1, 2016, we completed the sale of our general partner interest in TLP to an affiliate of ArcLight Capital Partners (“AcrLight”) for $350 million in cash. We also granted to ArcLight an option to purchase up to 800,000 of the approximately 3.2 million TLP common units we own. We will remain the long-term exclusive tenant in the TLP Southeast terminal system. We will retain TransMontaigne’s marketing business, which is a significant part of our refined products and renewables business, and TransMontaigne Products Services, LLC, its customer contracts and its line space on the Colonial and Plantation pipelines.

Note 18 —Condensed Consolidating Guarantor and Non-Guarantor Financial Information

Certain of our wholly owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the 2019 Notes and 2021 Notes (see Note 9). Pursuant to Rule 3-10 of Regulation S-X, we have presented in columnar format the condensed consolidating financial information for NGL Energy Partners LP, NGL Energy Finance Corp. (which, along with NGL Energy Partners LP, is a co-issuer of the 2019 Notes and 2021 Notes), the guarantor subsidiaries on a combined basis, and the non-guarantor subsidiaries on a combined basis in the tables below.

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, other than restrictions contained in TLP’s Credit Facility. None of the assets of the guarantor subsidiaries (other than the investments in non-guarantor subsidiaries) 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 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 condensed consolidating statement of cash flow tables below.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)

	December 31, 2015
	NGL Energy
	Partners LP		NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)		Finance Corp. (1)		Subsidiaries			Subsidiaries			Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	21,430	$	—	$	2,249		$	1,500		$	—		$	25,179
Accounts receivable—trade, net of allowance for doubtful accounts	—		—		569,304			12,317			—			581,621
Accounts receivable—affiliates	—		—		3,297			515			—			3,812
Inventories	—		—		411,981			2,107			—			414,088
Prepaid expenses and other current assets	—		—		115,673			1,803			—			117,476
Assets held for sale	—		—		87,383			—			—			87,383
Total current assets	21,430		—		1,189,887			18,242			—			1,229,559

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,415,391			557,534			—			1,972,925
GOODWILL	—		—		1,490,283			32,361			—			1,522,644
INTANGIBLE ASSETS, net of accumulated amortization	17,428		—		1,161,941			63,071			—			1,242,440
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		213,043			254,516			—			467,559
NET INTERCOMPANY RECEIVABLES (PAYABLES)	1,470,296		—		(1,454,047		)	(16,249		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,493,420		—		83,048			—			(1,576,468		)	—
LOAN RECEIVABLE—AFFILIATE	—		—		23,258			—			—			23,258
OTHER NONCURRENT ASSETS	—		—		104,942			1,144			—			106,086
Total assets	$	3,002,574	$	—	$	4,227,746		$	910,619		$	(1,576,468	)	$	6,564,471

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable—trade	$	—	$	—	$	498,378		$	12,931		$	—		$	511,309
Accounts payable—affiliates	1		—		10,888			153			—			11,042
Accrued expenses and other payables	16,624		—		167,131			9,540			—			193,295
Advance payments received from customers	—		—		72,786			876			—			73,662
Current maturities of long-term debt	—		—		6,804			796			—			7,600
Total current liabilities	16,625		—		755,987			24,296			—			796,908

LONG-TERM DEBT, net of current maturities	1,100,000		—		1,968,302			255,190			—			3,323,492
OTHER NONCURRENT LIABILITIES	—		—		10,037			3,195			—			13,232

EQUITY:
Partners’ equity	1,885,949		—		1,493,420			628,086			(2,121,358		)	1,886,097
Accumulated other comprehensive loss	—		—		—			(148		)	—			(148		)
Noncontrolling interests	—		—		—			—			544,890			544,890
Total equity	1,885,949		—		1,493,420			627,938			(1,576,468		)	2,430,839
Total liabilities and equity	$	3,002,574	$	—	$	4,227,746		$	910,619		$	(1,576,468	)	$	6,564,471

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes. Since the parent received the proceeds from the issuance of the 2019 Notes and 2021 Notes, all activity has been reflected in the parent column.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)

	March 31, 2015
	NGL Energy
	Partners LP		NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)		Finance Corp. (1)		Subsidiaries			Subsidiaries			Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	29,115	$	—	$	9,757		$	2,431		$	—		$	41,303
Accounts receivable—trade, net of allowance for doubtful accounts	—		—		1,007,001			17,225			—			1,024,226
Accounts receivable—affiliates	5		—		16,610			583			—			17,198
Inventories	—		—		440,026			1,736			—			441,762
Prepaid expenses and other current assets	—		—		104,528			16,327			—			120,855
Total current assets	29,120		—		1,577,922			38,302			—			1,645,344

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation	—		—		1,093,018			524,371			—			1,617,389
GOODWILL	—		—		1,372,690			30,071			—			1,402,761
INTANGIBLE ASSETS, net of accumulated amortization	17,834		—		1,195,896			74,613			—			1,288,343
INVESTMENTS IN UNCONSOLIDATED ENTITIES	—		—		217,600			255,073			—			472,673
NET INTERCOMPANY RECEIVABLES (PAYABLES)	1,363,792		—		(1,319,724		)	(44,068		)	—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES	1,834,738		—		56,690			—			(1,891,428		)	—
LOAN RECEIVABLE—AFFILIATE	—		—		8,154			—			—			8,154
OTHER NONCURRENT ASSETS	—		—		110,120			2,717			—			112,837
Total assets	$	3,245,484	$	—	$	4,312,366		$	881,079		$	(1,891,428	)	$	6,547,501

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable—trade	$	—	$	—	$	820,441		$	12,939		$	—		$	833,380
Accounts payable—affiliates	—		—		25,690			104			—			25,794
Accrued expenses and other payables	19,690		—		165,819			9,607			—			195,116
Advance payments received from customers	—		—		53,903			331			—			54,234
Current maturities of long-term debt	—		—		4,413			59			—			4,472
Total current liabilities	19,690		—		1,070,266			23,040			—			1,112,996

LONG-TERM DEBT, net of current maturities	1,100,000		—		1,395,100			250,199			—			2,745,299
OTHER NONCURRENT LIABILITIES	—		—		12,262			3,824			—			16,086

EQUITY:
Partners’ equity	2,125,794		—		1,834,738			604,125			(2,438,754		)	2,125,903
Accumulated other comprehensive loss	—		—		—			(109		)	—			(109		)
Noncontrolling interests	—		—		—			—			547,326			547,326
Total equity	2,125,794		—		1,834,738			604,016			(1,891,428		)	2,673,120
Total liabilities and equity	$	3,245,484	$	—	$	4,312,366		$	881,079		$	(1,891,428	)	$	6,547,501

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	Three Months Ended December 31, 2015
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp. (1)		Subsidiaries			Subsidiaries			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	—			—		84,823			22,015			(55		)	106,783
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

Operating Income	—			—		53,086			8,094			—			61,180

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

Income (Loss) Before Income Taxes	(17,830		)	—		38,871			8,982			—			30,023

INCOME TAX EXPENSE	—			—		(371		)	(31		)	—			(402		)

EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES	41,311			—		2,811			—			(44,122		)	—

Net Income	23,481			—		41,311			8,951			(44,122		)	29,621

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(16,217		)	(16,217		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(6,140		)	(6,140		)

NET INCOME ALLOCATED TO LIMITED PARTNERS	$	23,481		$	—	$	41,311		$	8,951		$	(66,479	)	$	7,264

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

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

REVENUES	$	—		$	—	$	4,519,060		$	58,058		$	(24,972	)	$	4,552,146

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

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

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

OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		4			1,238			—			1,242
Interest expense	(18,067		)	—		(10,108		)	(1,887		)	11			(30,051		)
Other income, net	—			—		3,314			68			(11		)	3,371

Income (Loss) Before Income Taxes	(18,067		)	—		31,303			(20,595		)	—			(7,359		)

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

EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES	7,149			—		(26,271		)	—			19,122			—

Net Income (Loss)	(10,918		)	—		7,149			(20,622		)	19,122			(5,269		)

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

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

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	(10,918	)	$	—	$	7,149		$	(20,622	)	$	1,690		$	(22,701	)

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

	Nine Months Ended December 31, 2015
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp. (1)		Subsidiaries			Subsidiaries			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	—			—		249,613			65,037			(180		)	314,470
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

Operating Income	—			—		31,641			15,056			—			46,697

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

Income (Loss) Before Income Taxes	(53,544		)	—		(1,355		)	19,996			—			(34,903		)

INCOME TAX (EXPENSE) BENEFIT	—			—		1,915			(69		)	—			1,846

EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES	7,581			—		7,021			—			(14,602		)	—

Net Income (Loss)	(45,963		)	—		7,581			19,927			(14,602		)	(33,057		)

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER												(47,742		)	(47,742		)

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS												(12,906		)	(12,906		)

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	(45,963	)	$	—	$	7,581		$	19,927		$	(75,250	)	$	(93,705	)

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

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

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

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

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

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

OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated entities	—			—		4,879			2,625			—			7,504
Interest expense	(47,660		)	—		(28,166		)	(3,404		)	34			(79,196		)
Other income, net	—			—		2,258			139			(34		)	2,363

Income (Loss) Before Income Taxes	(47,660		)	—		367			(16,742		)	—			(64,035		)

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

EQUITY IN NET LOSS OF CONSOLIDATED SUBSIDIARIES	(22,457		)	—		(25,934		)	—			48,391			—

Net Loss	(70,117		)	—		(22,457		)	(16,875		)	48,391			(61,058		)

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

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

NET LOSS ALLOCATED TO LIMITED PARTNERS	$	(70,117	)	$	—	$	(22,457	)	$	(16,875	)	$	7,112		$	(102,337	)

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 notes and 2021 Notes.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statements of Comprehensive Income (Loss)

(U.S. Dollars in Thousands)

	Three Months Ended December 31, 2015
	NGL Energy
	Partners LP		NGL Energy		Guarantor		Non-Guarantor			Consolidating
	(Parent) (1)		Finance Corp. (1)		Subsidiaries		Subsidiaries			Adjustments			Consolidated

Net income	$	23,481	$	—	$	41,311	$	8,951		$	(44,122	)	$	29,621

Other comprehensive loss	—		—		—		(12		)	—			(12		)

Comprehensive income	$	23,481	$	—	$	41,311	$	8,939		$	(44,122	)	$	29,609

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

	Three Months Ended December 31, 2014
	NGL Energy
	Partners LP			NGL Energy		Guarantor		Non-Guarantor			Consolidating
	(Parent) (2)			Finance Corp. (2)		Subsidiaries		Subsidiaries			Adjustments		Consolidated

Net income (loss)	$	(10,918	)	$	—	$	7,149	$	(20,622	)	$	19,122	$	(5,269	)

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

Comprehensive income (loss)	$	(10,918	)	$	—	$	7,149	$	(20,638	)	$	19,122	$	(5,285	)

(2) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statements of Comprehensive Income (Loss)

(U.S. Dollars in Thousands)

	Nine Months Ended December 31, 2015
	NGL Energy
	Partners LP			NGL Energy		Guarantor		Non-Guarantor			Consolidating
	(Parent) (1)			Finance Corp. (1)		Subsidiaries		Subsidiaries			Adjustments			Consolidated

Net income (loss)	$	(45,963	)	$	—	$	7,581	$	19,927		$	(14,602	)	$	(33,057	)

Other comprehensive loss	—			—		—		(39		)	—			(39		)

Comprehensive income (loss)	$	(45,963	)	$	—	$	7,581	$	19,888		$	(14,602	)	$	(33,096	)

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

	Nine Months Ended December 31, 2014
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor			Consolidating
	(Parent) (2)			Finance Corp. (2)		Subsidiaries			Subsidiaries			Adjustments		Consolidated

Net loss	$	(70,117	)	$	—	$	(22,457	)	$	(16,875	)	$	48,391	$	(61,058	)

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

Comprehensive loss	$	(70,117	)	$	—	$	(22,268	)	$	(16,917	)	$	48,391	$	(60,911	)

(2) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes .

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)

	Nine Months Ended December 31, 2015
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor
	(Parent) (1)			Finance Corp. (1)		Subsidiaries			Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(52,989	)	$	—	$	276,244		$	69,879		$	293,134

INVESTING ACTIVITIES:
Purchases of long-lived assets	—			—		(439,476		)	(57,671		)	(497,147		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	(624		)	—		(184,852		)	(1,880		)	(187,356		)
Cash flows from 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	—			—		—			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

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

At December 31, 2015 and March 31, 2015, and for the

Three Months and Nine Months Ended December 31, 2015 and 2014

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)

	Nine Months Ended December 31, 2014
	NGL Energy
	Partners LP			NGL Energy		Guarantor			Non-Guarantor
	(Parent) (1)			Finance Corp. (1)		Subsidiaries			Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(43,114	)	$	—	$	86,074		$	38,880		$	81,840

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

FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	—			—		3,016,000			80,700			3,096,700
Payments on revolving credit facilities	—			—		(2,542,000		)	(62,700		)	(2,604,700		)
Issuance of notes	400,000			—		—			—			400,000
Payments on other long-term debt	—			—		(5,454		)	(22		)	(5,476		)
Debt issuance costs	(8,003		)	—		(2,823		)	—			(10,826		)
Contributions from general partner	408			—		—			—			408
Distributions to partners	(176,051		)	—		—			—			(176,051		)
Distributions to noncontrolling interest owners	—			—		—			(17,497		)	(17,497		)
Proceeds from sale of common units, net of offering costs	370,376			—		—			—			370,376
Net changes in advances with consolidated entities	(541,510		)	—		566,390			(24,880		)	—
Other	—			—		(156		)	—			(156		)
Net cash provided by (used in) financing activities	45,220			—		1,031,957			(24,399		)	1,052,778
Net increase in cash and cash equivalents	2,106			—		14,845			3,165			20,116
Cash and cash equivalents, beginning of period	1,181			—		8,728			531			10,440
Cash and cash equivalents, end of period	$	3,287		$	—	$	23,573		$	3,696		$	30,556

(1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes .

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, 2015. The discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2015 (“Annual Report”).

Overview

We are a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At December 31, 2015, our operations include:

· Our refined products and renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the 2% general partner interest and a 19.6% limited partner interest in TransMontaigne Partners L.P. (“TLP”), which conducts refined products terminaling, storage, and transportation operations. See “Recent Developments” below for a discussion of the sale of the 2% general partner interest in TLP.

Crude Oil Logistics

Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. We attempt to reduce our exposure to price fluctuations by using back-to-back physical contracts whenever possible. When back-to-back physical contracts are not optimal, we enter into financially settled derivative contracts as economic hedges of our physical inventory, physical sales and physical purchase contracts.

Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets such as Cushing, Oklahoma. We seek to manage exposure to price fluctuations by entering into purchase and sale contracts of similar volumes based on similar indexes and by hedging exposure due to fluctuations in actual volumes and scheduled volumes. We use our transportation assets to move crude oil from the wellhead to the highest value market. Spreads between crude oil prices in different markets can fluctuate, which may expand or limit our opportunity to generate margins by transporting crude oil to different markets.

Table of Contents

The following table summarizes the range of low and high spot crude oil prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma for the periods indicated and the prices at period end:

	Spot Price Per Barrel
	Low		High		At Period End
Three Months Ended December 31,
2015	$	34.73	$	49.63	$	37.04
2014	53.27		91.01		53.27

Nine Months Ended December 31,
2015	$	34.73	$	61.43	$	37.04
2014	53.27		107.26		53.27

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

Water Solutions

Our water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, from the sale of recycled water and recovered hydrocarbons, and from the disposal of solids such as tank bottoms and drilling fluids, as well as truck and frac tank washouts. Our water processing facilities are strategically located near areas of high crude oil and natural gas production. A significant factor affecting the profitability of our water solutions segment is the extent of exploration and production in the areas near our facilities, which is generally based upon producers’ expectations about the profitability of drilling new wells. The primary customers of our Wyoming facility have committed to deliver a specified minimum volume of water to our facility under long-term contracts. The primary customers of our Colorado facilities have committed to deliver all wastewater produced at wells in a designated area to our facilities. One customer in Texas has committed to deliver at least 50,000 barrels of wastewater per day to our facilities. Most customers of our other facilities are not under volume commitments, although certain of our facilities are connected to producer locations by pipeline.

Liquids

Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the products to retailers, wholesalers, refiners, and petrochemical plants. Our liquids segment owns 19 terminals and a salt dome storage facility, operates a fleet of leased railcars, and leases underground storage capacity. We attempt to reduce our exposure to price fluctuations by using back-to-back contracts and pre-sale agreements that allow us to lock in a margin on a percentage of our winter volumes. We also enter into financially settled derivative contracts as economic hedges of our physical inventory, physical sales and physical purchase contracts.

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

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

Table of Contents

The following table summarizes the range of low and high spot propane prices per gallon at Conway, Kansas, and Mt. Belvieu, Texas, two of our main pricing hubs, for the periods indicated and the prices at period end:

	Conway, Kansas						Mt. Belvieu, Texas
	Spot Price Per Gallon						Spot Price Per Gallon
	Low		High		At Period End		Low		High		At Period End
Three Months Ended December 31,
2015	$	0.29	$	0.46	$	0.33	$	0.35	$	0.50	$	0.38
2014	0.42		1.09		0.42		0.48		1.06		0.48

Nine Months Ended December 31,
2015	$	0.28	$	0.51	$	0.33	$	0.32	$	0.57	$	0.38
2014	0.42		1.13		0.42		0.48		1.13		0.48

The following table summarizes the range of low and high spot butane prices per gallon at Mt. Belvieu, Texas for the periods indicated and the prices at period end:

	Spot Price Per Gallon
	Low		High		At Period End
Three Months Ended December 31,
2015	$	0.51	$	0.68	$	0.56
2014	0.66		1.24		0.66

Nine Months Ended December 31,
2015	$	0.46	$	0.68	$	0.56
2014	0.66		1.30		0.66

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

Retail Propane

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

A significant factor affecting the profitability of our retail propane segment is our ability to maintain our product margin. Product margin is the difference between our sales prices and our total product costs, including transportation and storage. We monitor wholesale propane prices daily and adjust our retail prices accordingly. We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.

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

Refined Products and Renewables

Our refined products and renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We purchase refined petroleum products primarily in the Gulf Coast, Southeast, and Midwest regions of the United States and schedule them for delivery primarily on the Colonial, Plantation, and Magellan pipelines. We sell our products to commercial and industrial end users, independent retailers, distributors, marketers, government entities, and other wholesalers of refined petroleum products. We sell our products at TLP’s terminals and at terminals owned by third parties.

Table of Contents

The following table summarizes the range of low and high spot gasoline prices per barrel using NYMEX gasoline prompt-month futures for the periods indicated and the prices at period end:

	Spot Price Per Barrel
	Low		High		At Period End
Three Months Ended December 31,
2015	$	49.35	$	60.71	$	53.22
2014	60.48		102.90		60.48

Nine Months Ended December 31,
2015	$	49.35	$	90.15	$	53.22
2014	60.48		131.46		60.48

The following table summarizes the range of low and high spot diesel prices per barrel using NYMEX ULSD prompt-month futures for the periods indicated and the prices at period end:

	Spot Price Per Barrel
	Low		High		At Period End
Three Months Ended December 31,
2015	$	45.32	$	67.68	$	46.23
2014	77.70		111.72		77.70

Nine Months Ended December 31,
2015	$	45.32	$	84.68	$	46.23
2014	77.70		128.10		77.70

Recent Developments

Grand Mesa Pipeline

We estimate that our share of the cost to construct the Joint Pipeline will be $250 million. We paid $125 million towards the construction of the pipeline during the three months ended December 31, 2015, and we expect to pay the remaining amount during the calendar year ending December 31, 2016.

Prior to reaching the agreement with Saddlehorn, we purchased $87.4 million of pipe that we expected to use for the Grand Mesa Pipeline. During the three months ended December 31, 2015, we reclassified this pipe to assets held for sale. To determine the value of the pipe at December 31, 2015, we inquired of a third party manufacturer as to the current cost of similar pipe. Based on the information we received, the fair value of the pipe approximated our carrying value. To facilitate the sale of this pipe, we notified potential buyers at the end of December 2015 that we would be accepting bids for the pipe through February 15, 2016. Initial discussions held in January 2016 with potential buyers indicated to us that we would probably need to sell the pipe at an amount less than the carrying value at December 31, 2015. Based on these indications, we expect to record a loss on the sale of these assets during the fourth quarter of fiscal year 2016. In addition, we reclassified $47.0 million of costs to acquire land, rights-of-way and easements on the originally-planned Grand Mesa Pipeline route as intangible assets in our condensed consolidated balance sheet.

Sale of General Partner Interest in TLP

On February 1, 2016, we completed the sale of our general partner interest in TLP to an affiliate of ArcLight Capital Partners (“ArcLight”) for $350 million in cash. We also granted to ArcLight an option to purchase up to 800,000 of the approximately 3.2 million TLP common units that we own. We will remain the long-term exclusive tenant in the TLP Southeast terminal system. We will retain TransMontaigne’s marketing business, which is a significant part of our refined products and renewables business, and TransMontaigne Product Services, LLC, its customer contracts and its line space on the Colonial and Plantation pipelines.

Table of Contents

Acquisitions

As described below, we completed numerous acquisitions during the year ended March 31, 2015 and the nine months ended December 31, 2015. These acquisitions impact the comparability of our results of operations between our current and prior fiscal years.

Year Ending March 31, 2016

· In August 2015, we acquired 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 are party to a development agreement that requires us to purchase water solutions facilities developed by the other party to the agreement. During the nine months ended December 31, 2015, we purchased 12 water treatment and disposal facilities under this development agreement.

· During the nine months ended December 31, 2015, we acquired five retail propane businesses.

Year Ended March 31, 2015

· In February 2015, we acquired Sawtooth NGL Caverns, LLC (“Sawtooth”), which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets and entered into a construction agreement to expand the storage capacity of the facility.

· In November 2014, we acquired two saltwater disposal facilities in the Bakken shale play in North Dakota.

· In July 2014, we acquired TransMontaigne Inc. (“TransMontaigne”). As part of this transaction, we also purchased inventory from the previous owner of TransMontaigne. The operations of TransMontaigne include the marketing of refined products. As part of this transaction, we acquired the 2.0% general partner interest, the incentive distribution rights, a 19.7% limited partner interest in TLP, and assumed certain terminaling service agreements with TLP from an affiliate of the previous owner of TransMontaigne.

· We are party to a development agreement that requires us to purchase water solutions facilities developed by the other party to the agreement. During the year ended March 31, 2015, we purchased 16 water treatment and disposal facilities under this development agreement.

· During the year ended March 31, 2015, we acquired eight retail propane businesses.

Summary Discussion of Operating Results for the Three Months Ended December 31, 2015

We generated operating income of $61.2 million during the three months ended December 31, 2015, compared to $18.1 million during the three months ended December 31, 2014.

Our crude oil logistics segment generated operating income of $0.8 million during the three months ended December 31, 2015, compared to an operating loss of $26.8 million during the three months ended December 31, 2014. Per-barrel product margins were higher during the three months ended December 31, 2015 than during the three months ended December 31, 2014 due primarily to a lower of cost or market adjustment of $20.0 million recorded at December 31, 2014, partially offset by lower crude oil prices, which resulted in increased market pressure. The decrease in operating loss was also due in part to $1.5 million of expense recorded during the three months ended December 31, 2014 related to certain employee retention and severance costs associated with the Gavilon, LLC (“Gavilon Energy”) and TransMontaigne acquisitions.

Our water solutions segment generated an operating loss of $5.8 million during the three months ended December 31, 2015, compared to operating income of $34.5 million during the three months ended December 31, 2014. The increase in operating loss was due primarily to lower volumes and a decrease in revenues from the sale of recovered hydrocarbons resulting from lower crude oil prices, which were partially offset by the acquisition and development of new facilities. We have historically entered into derivatives to protect against the risk of a decline in the price of crude oil we expect to recover in the process of treating the wastewater. During the three months ended December 31, 2015 and 2014, cost of sales was reduced by $2.9 million and $29.1 million, respectively, of net gains on derivatives.

Table of Contents

Our liquids segment generated operating income of $32.9 million during the three months ended December 31, 2015, compared to an operating loss of $14.0 million during the three months ended December 31, 2014. Product margins for propane were $21.9 million higher during the three months ended December 31, 2015 than during the three months ended December 31, 2014 , as a sharp decrease in propane prices during the three months ended December 31, 2014 had an adverse impact on margins during that period. Operating income during the three months ended December 31, 2014 was also reduced by a loss of $29.9 million on the sale of a natural gas liquids terminal. Additionally, Sawtooth, which we acquired in February 2015, generated $2.5 million of operating income during the three months ended December 31, 2015.

Our retail propane segment generated operating income of $14.5 million during the three months ended December 31, 2015, compared to operating income of $21.5 million during the three months ended December 31, 2014. Volumes were lower during the three months ended December 31, 2015 due to warmer weather conditions.

Our refined products and renewables segment generated operating income of $31.7 million during the three months ended December 31, 2015, compared to operating income of $29.0 million during the three months ended December 31, 2014. The increase in operating income resulted from lower operating and general administrative expenses, partially offset by lower margins. Operating expenses during the three months ended December 31, 2015 were reduced by the receipt of insurance proceeds for certain environmental remediation matters. General and administrative expenses during the three months ended December 31, 2014 included $6.0 million of compensation expense related to the termination of certain TransMontaigne employees. A significant portion of our refined product purchases and sales are priced based on a Gulf Coast index plus a specified differential. We use futures contracts with New York Harbor pricing to hedge the risk of price changes on our inventory valuation. Changes in the spreads between Gulf Coast and New York Harbor prices can impact the effectiveness of these futures contracts as hedges. During the three months ended December 31, 2015, Gulf Coast prices declined more than New York Harbor prices, and as a result, the futures contracts were less effective as hedges of our inventory valuation, which had an unfavorable impact on our product margins. We generally expect the spreads between the Gulf Coast and New York Harbor prices to be more consistent over the course of a year than during any individual quarter within the year. The tenor of these futures contracts, which are typically six months to one year in duration at inception, can also contribute to volatility in earnings among individual quarters within a fiscal year.

We recorded earnings from our equity method investments of $2.9 million during the three months ended December 31, 2015, compared to $1.2 million during the three months ended December 31, 2014. The increase was due primarily to an increase of $2.4 million in earnings from our investments in Glass Mountain Pipeline, LLC (“Glass Mountain”), Battleground Oil Specialty Terminal Company LLC (“BOSTCO”), and Frontera Brownsville LLC (“Frontera”) , partially offset by a decrease of $0.7 million in earnings from our investments in an ethanol production facility and a water supply company.

We incurred interest expense of $36.2 million during the three months ended December 31, 2015, compared to $30.1 million during the three months ended December 31, 2014. The increase was due primarily to borrowings to finance acquisitions and capital expenditures.

Table of Contents

Consolidated Results of Operations

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

	Three Months Ended December 31,						Nine Months Ended December 31,
	2015			2014			2015			2014
	(in thousands)
Total revenues	$	2,685,006		$	4,552,146		$	9,416,670		$	13,581,286
Total cost of sales	2,433,500			4,311,668			8,761,877			13,025,186
Operating expenses	106,783			97,761			314,470			262,616
General and administrative expenses	23,035			44,230			114,814			113,742
Depreciation and amortization	59,180			50,335			175,772			139,809
Loss on disposal or impairment of assets, net	1,328			30,073			3,040			34,639
Operating income	61,180			18,079			46,697			5,294
Equity in earnings of unconsolidated entities	2,858			1,242			14,008			7,504
Interest expense	(36,176		)	(30,051		)	(98,549		)	(79,196		)
Other income, net	2,161			3,371			2,941			2,363
Income (loss) before income taxes	30,023			(7,359		)	(34,903		)	(64,035		)
Income tax (expense) benefit	(402		)	2,090			1,846			2,977
Net income (loss)	29,621			(5,269		)	(33,057		)	(61,058		)
Less: Net income allocated to general partner	(16,217		)	(11,783		)	(47,742		)	(32,220		)
Less: Net income attributable to noncontrolling interests	(6,140		)	(5,649		)	(12,906		)	(9,059		)
Net income (loss) allocated to limited partners	$	7,264		$	(22,701	)	$	(93,705	)	$	(102,337	)

See the detailed discussion of revenues, cost of sales, operating expenses, general and administrative expenses, and depreciation and amortization expense by segment below. The acquisitions described above under “Acquisitions” impact the comparability of our results of operations between our current and prior fiscal years.

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 parent equity, 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, and equity-based compensation expense. We also include in Adjusted EBITDA certain inventory valuation adjustments related to our refined products and renewables segment, as described 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 table below reflects the difference between the market value of the inventory of our refined products and renewables segment at the

Table of Contents

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 impact Adjusted EBITDA.

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

	Three Months Ended December 31,						Nine Months Ended December 31,
	2015			2014			2015			2014
	(in thousands)
Net income (loss)	$	29,621		$	(5,269	)	$	(33,057	)	$	(61,058	)
Less: Net income attributable to noncontrolling interests	(6,140		)	(5,649		)	(12,906		)	(9,059		)
Net income (loss) attributable to parent equity	23,481			(10,918		)	(45,963		)	(70,117		)
Interest expense	34,740			28,892			92,908			77,338
Income tax expense (benefit)	384			(2,099		)	(1,900		)	(2,997		)
Depreciation and amortization	55,261			51,065			162,728			143,781
EBITDA	113,866			66,940			207,773			148,005
Net unrealized gains on derivatives	(1,748		)	(4,724		)	(4,494		)	(13,414		)
Inventory valuation adjustment	(16,524		)	—			2,831			—
Lower of cost or market adjustments	13,251			29,399			7,325			32,236
Loss on disposal or impairment of assets, net	1,343			30,072			3,056			34,680
Equity-based compensation expense (1)	3,032			14,870			52,712			36,529
Adjusted EBITDA	$	113,220		$	136,557		$	269,203		$	238,036

(1) Equity-based compensation expense in the table above may differ from equity-based compensation expense reported in Note 12 to our condensed consolidated financial statements included in this Quarterly Report on Form 10-Q (“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 12 to our condensed consolidated financial statements only include expenses associated with equity-based awards that have been formally granted.

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

	Three Months Ended December 31,						Nine Months Ended December 31,
	2015			2014			2015			2014
	(in thousands)
Reconciliation to condensed consolidated statements of operations:
Depreciation and amortization per EBITDA table	$	55,261		$	51,065		$	162,728		$	143,781
Intangible asset amortization recorded to cost of sales	(1,701		)	(1,818		)	(5,102		)	(5,939		)
Depreciation and amortization of unconsolidated entities	(5,096		)	(5,485		)	(15,221		)	(14,100		)
Depreciation and amortization attributable to noncontrolling interests	10,716			6,573			33,367			16,067
Depreciation and amortization per condensed consolidated statements of operations	$	59,180		$	50,335		$	175,772		$	139,809

	Nine Months Ended December 31,
	2015			2014
	(in thousands)
Reconciliation to condensed consolidated statements of cash flows:
Depreciation and amortization per EBITDA table	$	162,728		$	143,781
Amortization of debt issuance costs recorded to interest expense	10,207			6,480
Depreciation and amortization of unconsolidated entities	(15,221		)	(14,100		)
Depreciation and amortization attributable to noncontrolling interests	33,367			16,067
Depreciation and amortization per condensed consolidated statements of cash flows	$	191,081		$	152,228

Table of Contents

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

	Three Months Ended December 31,				Nine Months Ended December 31,
	2015		2014		2015		2014
	(in thousands)
Interest expense per EBITDA table	$	34,740	$	28,892	$	92,908	$	77,338
Interest expense attributable to noncontrolling interests	1,165		1,139		4,502		1,761
Gain on extinguishment of debt of unconsolidated entities	—		—		693		—
Other	271		20		446		97
Interest expense per condensed consolidated statements of operations	$	36,176	$	30,051	$	98,549	$	79,196

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 acquired in acquisitions.

	Capital Expenditures
	Expansion (1)		Maintenance (2)		Total
	(in thousands)
Three Months Ended December 31,
2015	$	258,609	$	13,140	$	271,749
2014	42,426		11,280		53,706

Nine Months Ended December 31,
2015	$	459,141	$	39,146	$	498,287
2014	108,101		28,456		136,557

(1) Includes expansion capital expenditures for TLP of $1.1 million and $2.7 million during the three months ended December 31, 2015 and 2014, respectively, and $10.4 million and $3.7 million during the nine months ended December 31, 2015 and 2014, respectively.

(2) Includes maintenance capital expenditures for TLP of $4.3 million and $1.9 million during the three months ended December 31, 2015 and 2014, respectively, and $11.4 million and $2.0 million during the nine months ended December 31, 2015 and 2014, respectively.

Table of Contents

The following tables reconcile Adjusted EBITDA to operating income (loss) for each of our reportable segments for the periods indicated:

	Three Months Ended December 31, 2015
													Refined
													Products
	Crude Oil			Water						Retail			and			Corporate
	Logistics			Solutions			Liquids			Propane			Renewables			and Other			Consolidated
	(in thousands)
Operating income (loss)	$	804		$	(5,778	)	$	32,921		$	14,450		$	31,702		$	(12,919	)	$	61,180
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		)
Equity-based compensation expense	—			—			—			—			277			2,973			3,250
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			(5		)	—			—			1,328
Equity in earnings (losses) of unconsolidated entities	624			(381		)	—			(177		)	2,792			—			2,858
Other income (expense), net	(672		)	569			70			186			(20		)	2,028			2,161
Depreciation and amortization of unconsolidated entities	2,478			304			—			—			2,314			—			5,096
Adjusted EBITDA attributable to noncontrolling interests	—			(746		)	—			(403		)	(17,364		)	—			(18,513		)
Adjusted EBITDA	$	10,524		$	21,557		$	35,371		$	23,018		$	29,299		$	(6,549	)	$	113,220

	Three Months Ended December 31, 2014
													Refined
													Products
	Crude Oil			Water						Retail			and			Corporate
	Logistics			Solutions			Liquids			Propane			Renewables			and Other			Consolidated
	(in thousands)
Operating income (loss)	$	(26,814	)	$	34,505		$	(14,048	)	$	21,477		$	28,958		$	(25,999	)	$	18,079
Depreciation and amortization	10,630			17,807			2,838			7,949			9,788			1,323			50,335
Amortization recorded to cost of sales	109			—			471			—			1,211			27			1,818
Net unrealized (gains) losses on derivatives	7,040			(5,479		)	6,541			(682		)	(12,144		)	—			(4,724		)
Equity-based compensation expense	—			—			—			—			23			14,863			14,886
Lower of cost or market adjustments	17,379			—			390			—			11,630			—			29,399
Loss on disposal or impairment of assets, net	98			38			29,886			50			1			—			30,073
Equity in earnings (losses) of unconsolidated entities	(613		)	(26		)	—			—			1,881			—			1,242
Other income (expense), net	(689		)	141			35			258			5			3,621			3,371
Depreciation and amortization of unconsolidated entities	2,496			417			—			—			2,572			—			5,485
Adjusted EBITDA attributable to noncontrolling interests	—			(515		)	—			(404		)	(12,488		)	—			(13,407		)
Adjusted EBITDA	$	9,636		$	46,888		$	26,113		$	28,648		$	31,437		$	(6,165	)	$	136,557

Table of Contents

	Nine Months Ended December 31, 2015
													Refined
													Products
	Crude Oil			Water						Retail			and			Corporate
	Logistics			Solutions			Liquids			Propane			Renewables			and Other			Consolidated
	(in thousands)
Operating income (loss)	$	12,689		$	(8,645	)	$	52,820		$	11,985		$	59,478		$	(81,630	)	$	46,697
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		)
Equity-based compensation expense	—			—			—			—			862			52,529			53,391
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 in earnings (losses) of unconsolidated entities	2,951			(369		)	—			(336		)	11,762			—			14,008
Other income (expense), net	(6,432		)	1,352			278			812			236			6,695			2,941
Depreciation and amortization of unconsolidated entities	7,443			924			—			—			6,854			—			15,221
Adjusted EBITDA attributable to noncontrolling interests	—			(2,570		)	—			(528		)	(49,533		)	—			(52,631		)
Adjusted EBITDA	$	44,624		$	59,795		$	62,819		$	38,361		$	82,057		$	(18,453	)	$	269,203

	Nine Months Ended December 31, 2014
													Refined
													Products
	Crude Oil			Water						Retail			and			Corporate
	Logistics			Solutions			Liquids			Propane			Renewables			and Other			Consolidated
	(in thousands)
Operating income (loss)	$	(25,313	)	$	48,390		$	(4,032	)	$	16,829		$	36,525		$	(67,105	)	$	5,294
Depreciation and amortization	29,601			52,472			9,423			23,204			22,549			2,560			139,809
Amortization recorded to cost of sales	(7		)	—			1,459			—			2,825			1,662			5,939
Net unrealized (gains) losses on derivatives	3,980			(12,050		)	7,681			(881		)	(12,144		)	—			(13,414		)
Equity-based compensation expense	—			—			—			—			23			36,522			36,545
Lower of cost or market adjustments	20,000			—			606			—			11,630			—			32,236
Loss (gain) on disposal or impairment of assets, net	293			4,385			29,768			350			(19		)	(138		)	34,639
Equity in earnings of unconsolidated entities	2,420			—			—			—			5,084			—			7,504
Other income (expense), net	(2,796		)	158			24			1,185			(26		)	3,818			2,363
Depreciation and amortization of unconsolidated entities	7,675			645			—			—			5,780			—			14,100
Adjusted EBITDA attributable to noncontrolling interests	—			(728		)	—			(312		)	(25,939		)	—			(26,979		)
Adjusted EBITDA	$	35,853		$	93,272		$	44,929		$	40,375		$	46,288		$	(22,681	)	$	238,036

Segment Operating Results for the Three Months Ended December 31, 2015 and 2014

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 expanded our liquids business through the February 2015 acquisition of Sawtooth. We expanded our retail propane business through numerous acquisitions of retail propane businesses. 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 ended December 31, 2015 are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2016.

Table of Contents

Volumes

The following table summarizes the volume of product sold and water received for the periods indicated. Volumes shown in the following table include intersegment sales.

	Three Months Ended December 31,
Segment	2015	2014	Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)	10,824	22,658	(11,834	)

Water solutions
Water received (barrels)	55,648	47,063	8,585

Liquids
Propane sold (gallons)	348,511	380,528	(32,017	)
Other products sold (gallons)	225,695	230,312	(4,617	)

Retail propane
Propane sold (gallons)	42,436	48,324	(5,888	)
Distillates sold (gallons)	9,102	9,381	(279	)

Refined products and renewables
Refined products sold (barrels)	26,134	19,953	6,181
Renewable products sold (barrels)	1,461	1,448	13

Revenues and Cost of Sales by Segment

The following table summarizes our revenues and cost of sales by segment for the periods indicated:

	Three Months Ended December 31,
	2015								2014
				Cost of			Product					Cost of			Product
	Revenues			Sales			Margin		Revenues			Sales			Margin
	(in thousands)
Crude oil logistics	$	521,286		$	497,390		$	23,896	$	1,701,249		$	1,703,738		$	(2,489	)
Water solutions	45,438			(3,128		)	48,566		50,241			(29,085		)	79,326
Liquids	377,711			324,950			52,761		734,865			706,779			28,086
Retail propane	100,145			45,974			54,171		139,765			81,172			58,593
Refined products and renewables	1,666,723			1,594,611			72,112		1,984,048			1,905,625			78,423
Corporate and other	—			—			—		(1,281		)	176			(1,457		)
Eliminations	(26,297		)	(26,297		)	—		(56,741		)	(56,737		)	(4		)
Total	$	2,685,006		$	2,433,500		$	251,506	$	4,552,146		$	4,311,668		$	240,478

Table of Contents

Operating Income (Loss) by Segment

The following table summarizes our operating income (loss) by segment for the periods indicated:

	Three Months Ended December 31,
Segment	2015			2014			Change
	(in thousands)
Crude oil logistics	$	804		$	(26,814	)	$	27,618
Water solutions	(5,778		)	34,505			(40,283		)
Liquids	32,921			(14,048		)	46,969
Retail propane	14,450			21,477			(7,027		)
Refined products and renewables	31,702			28,958			2,744
Corporate and other	(12,919		)	(25,999		)	13,080
Operating income	$	61,180		$	18,079		$	43,101

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,
	2015		2014 (1)			Change
	(in thousands)
Revenues:
Crude oil sales	$	508,863	$	1,689,106		$	(1,180,243	)
Crude oil transportation and other	12,423		12,143			280
Total revenues (2)	521,286		1,701,249			(1,179,963		)
Expenses:
Cost of sales	497,390		1,703,738			(1,206,348		)
Operating expenses	10,936		10,070			866
General and administrative expenses	2,115		3,625			(1,510		)
Depreciation and amortization expense	10,041		10,630			(589		)
Total expenses	520,482		1,728,063			(1,207,581		)
Segment operating income (loss)	$	804	$	(26,814	)	$	27,618

(1) During the three months ended September 30, 2015, we made certain changes in the way we attribute revenues to the categories shown in the table above. These changes did not impact total revenues. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

(2) Revenues include $1.9 million and $6.4 million of intersegment sales during the three months ended December 31, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues . Our crude oil logistics segment generated $508.9 million of revenue from crude oil sales during the three months ended December 31, 2015, selling 10.8 million barrels at an average price of $47.01 per barrel. During the three months ended December 31, 2014, our crude oil logistics segment generated $1.7 billion of revenue from crude oil sales, selling 22.7 million barrels at an average price of $74.55 per barrel. The decrease in revenue per barrel was due primarily to the sharp decline in crude oil prices after September 30, 2014. The decrease in our sales volumes was due primarily to a slowdown in crude oil production and new drilling of crude oil in the current crude oil price environment.

Crude oil transportation and other revenues were $12.4 million during the three months ended December 31, 2015, compared to $12.1 million during the three months ended December 31, 2014.

Cost of Sales . Our cost of crude oil sold was $497.4 million during the three months ended December 31, 2015, as we sold 10.8 million barrels at an average cost of $45.95 per barrel. Our cost of sales during the three months ended December 31, 2015 was reduced by $3.9 million of net unrealized gains on derivatives and $4.0 million of net realized gains on derivatives. During the three

Table of Contents

months ended December 31, 2014, our cost of crude oil sold was $1.7 billion, as we sold 22.7 million barrels at an average cost of $75.19 per barrel. Our cost of sales during the three months ended December 31, 2014 was increased by $7.0 million of net unrealized losses on derivatives and was reduced by $30.8 million of net realized gains on derivatives. The following table summarizes our product margin (loss) for crude oil sales (in thousands, except per barrel amounts) for the periods indicated:

	Three Months Ended December 31,
	2015			2014

Crude oil sales revenues	$	508,863		$	1,689,106
Crude oil cost of sales	(497,390		)	(1,703,738		)
Crude oil product margin (loss)	$	11,473		$	(14,632	)

Crude oil sold (barrels)	10,824			22,658

Product margin (loss) per barrel	$	1.060		$	(0.646	)

Per-barrel product margins were higher during the three months ended December 31, 2015 than during the three months ended December 31, 2014 due primarily to a lower of cost or market adjustment of $20.0 million recorded at December 31, 2014, partially offset by lower crude oil prices, which resulted in increased market pressure.

The decrease in volumes during the three months December 31, 2015, as compared to the three months ended December 31, 2014, is due primarily to lower physical barrels being sold due to reduced production as a result of lower prices. Also, we had an increase in buy/sell transactions during the three months ended December 31, 2015, as we took advantage of the contango market. 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.

Operating Expenses . Our crude oil logistics segment incurred operating expenses of $10.9 million during the three months ended December 31, 2015, compared to $10.1 million during the three months ended December 31, 2014. The increase was due primarily to a shift in the recording of incentive compensation expense related to bonuses from the crude oil logistics segment to “corporate and other” during the three months ended December 31, 2014. See further discussion within the “Corporate and Other” section below. For the three months ended December 31, 2015, operating expenses included costs related to storage and handling of assets classified as held for sale (see Note 4 to our unaudited condensed consolidated financial statements).

General and Administrative Expenses . Our crude oil logistics segment incurred general and administrative expenses of $2.1 million during the three months ended December 31, 2015, compared to $3.6 million during the three months ended December 31, 2014. General and administrative expenses during the three months ended December 31, 2014 included $1.4 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses were paid in December 2014. General and administrative expenses during the three months ended December 31, 2014 also included $0.1 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense . Our crude oil logistics segment incurred depreciation and amortization expense of $10.0 million during the three months ended December 31, 2015, compared to $10.6 million during the three months ended December 31, 2014.

Table of Contents

Water Solutions

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

	Three Months Ended December 31,
	2015			2014			Change
	(in thousands)
Revenues:
Service fees	$	35,138		$	30,870		$	4,268
Recovered hydrocarbons	8,414			19,355			(10,941		)
Water transportation	—			16			(16		)
Other revenues	1,886			—			1,886
Total revenues	45,438			50,241			(4,803		)
Expenses:
Cost of sales—derivative gain (1)	(2,887		)	(29,137		)	26,250
Cost of sales—other	(241		)	52			(293		)
Operating expenses	30,009			26,373			3,636
General and administrative expenses	691			641			50
Depreciation and amortization expense	23,644			17,807			5,837
Total expenses	51,216			15,736			35,480
Segment operating income (loss)	$	(5,778	)	$	34,505		$	(40,283	)

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

The following tables summarize activity separated between the following categories:

· facilities we owned before September 30, 2014, which we refer to below as “existing facilities”; and

· facilities we acquired or developed after September 30, 2014, 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,
	2015					2014
			Water	Fees Per				Water	Fees Per
	Service		Barrels	Water Barrel		Service		Barrels	Water Barrel
	Fees		Processed	Processed		Fees		Processed	Processed

Existing facilities	$	21,978	30,486	$	0.72	$	29,507	45,097	$	0.65
Recently acquired or developed facilities	13,160		25,162	0.52		1,363		1,966	0.69
Total	$	35,138	55,648	0.63		$	30,870	47,063	0.66

The decrease in the volume processed at our existing facilities during the three months ended December 31, 2015 compared to the three months ended December 31, 2014 was due primarily to a slowdown in customer production as a result of the lower crude oil prices, and was also due in part to migration of volumes from existing facilities to recently developed or acquired facilities due to the location of the 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,
	2015					2014
	Recovered		Water	Revenue Per		Recovered		Water	Revenue Per
	Hydrocarbon		Barrels	Water Barrel		Hydrocarbon		Barrels	Water Barrel
	Revenue		Processed	Processed		Revenue		Processed	Processed

Existing facilities	$	5,331	30,486	$	0.17	$	18,442	45,097	$	0.41
Recently acquired or developed facilities	3,083		25,162	0.12		913		1,966		0.46
Total	$	8,414	55,648	0.15		$	19,355	47,063		0.41

The decrease in revenue per barrel associated with recovered hydrocarbons was due primarily to the sharp decline in crude oil prices after September 30, 2014 and a decrease in the volume of hydrocarbons recovered per barrel of water processed.

Water Transportation Revenues. Our water solutions segment generated less than $0.1 million of water transportation revenue during the three months ended December 31, 2014. These revenues related to our water transportation business, which we sold during September 2014.

Other Revenues . Our water solutions segment generated $1.9 million of other revenues during the three months ended December 31, 2015 relating to the disposal of solids.

Cost of Sales . We enter into derivatives in our water solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expect to recover when processing the wastewater. Our cost of sales during the three months ended December 31, 2015 was reduced by $6.6 million of net realized gains on derivatives and was increased by $3.7 million of net unrealized losses on derivatives. Our cost of sales during the three months ended December 31, 2014 was reduced by $5.5 million of net unrealized gains on derivatives and $23.6 million of net realized gains on derivatives. In December 2014, we settled derivative contracts that had scheduled settlement dates from April 2015 through September 2015, in order to lock in the gains on those derivatives.

Operating Expenses . The following table summarizes our operating expenses for the periods indicated:

	Three Months Ended December 31,
	2015		2014		Change
	(in thousands)
Existing facilities	$	19,844	$	25,399	$	(5,555	)
Recently acquired or developed facilities	10,165		974		9,191
Total	$	30,009	$	26,373	$	3,636

The decrease in operating expenses for existing facilities was due primarily to lower operating costs of water disposal wells at existing facilities due to lower volumes processed.

General and Administrative Expenses . Our water solutions segment incurred general and administrative expenses of $0.7 million during the three months ended December 31, 2015, compared to $0.6 million during the three months ended December 31, 2014.

Table of Contents

Depreciation and Amortization Expense . Our water solutions segment incurred depreciation and amortization expense of $23.6 million during the three months ended December 31, 2015, compared to $17.8 million during the three months ended December 31, 2014. Of the increase, $3.7 million related to recently acquired or developed facilities.

Liquids

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

	Three Months Ended December 31,
	2015		2014 (1)			Change
	(in thousands)
Revenues:
Propane sales	$	188,930	$	396,248		$	(207,318	)
Other product sales	180,620		329,943			(149,323		)
Other revenues	8,161		8,674			(513		)
Total revenues (2)	377,711		734,865			(357,154		)
Expenses:
Cost of sales—propane	170,558		399,783			(229,225		)
Cost of sales—other products	150,203		301,609			(151,406		)
Cost of sales—other	4,189		5,387			(1,198		)
Operating expenses	14,617		7,348			7,269
Loss on disposal or impairment of assets, net	5		29,886			(29,881		)
General and administrative expenses	1,681		2,062			(381		)
Depreciation and amortization expense	3,537		2,838			699
Total expenses	344,790		748,913			(404,123		)
Segment operating income (loss)	$	32,921	$	(14,048	)	$	46,969

(1) During the three months ended December 31, 2015, we made certain changes in the way we attribute revenues and railcar cost of sales to the categories shown in the table above. These changes did not impact total revenues or total cost of sales. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

(2) Revenues include $24.2 million and $49.8 million of intersegment sales during the three months ended December 31, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues . Our liquids segment generated $188.9 million of wholesale propane sales revenue during the three months ended December 31, 2015, selling 348.5 million gallons at an average price of $0.54 per gallon. During the three months ended December 31, 2014, our liquids segment generated $396.2 million of wholesale propane sales revenue, selling 380.5 million gallons at an average price of $1.04 per gallon. The decrease in the volume of propane sales was due to significantly warm temperatures throughout our primary trade territories and competitive pressures resulting from high levels of supply in certain markets.

Our liquids segment generated $180.6 million of other wholesale products sales revenue during the three months ended December 31, 2015, selling 225.7 million gallons at an average price of $0.80 per gallon. During the three months ended December 31, 2014, our liquids segment generated $329.9 million of other wholesale products sales revenue, selling 230.3 million gallons at an average price of $1.43 per gallon. The decrease in the volume of other wholesale products sold was due in part to the loss of a butane customer.

Our liquids segment generated $8.2 million of other revenues during the three months ended December 31, 2015, compared to $8.7 million during the three months ended December 31, 2014. This revenue includes storage, terminaling and transportation services income. The decrease was due primarily to lower hauling revenues due to declining market conditions, partially offset by revenues related to Sawtooth, which we acquired in February 2015.

Cost of Sales . Our cost of wholesale propane sales was $170.6 million during the three months ended December 31, 2015, as we sold 348.5 million gallons at an average cost of $0.49 per gallon. Our cost of wholesale propane sales during the three months ended December 31, 2015 was decreased by $1.7 million of net unrealized gains on derivatives. During the three months ended December 31, 2014, our cost of wholesale propane sales was $399.8 million, as we sold 380.5 million gallons at an average cost of $1.05 per gallon.

Table of Contents

Our cost of wholesale propane sales during the three months ended December 31, 2014 was increased by $6.5 million of net unrealized losses on derivatives. The following table summarizes our product margin (loss) for propane sales (in thousands, except per gallon amounts) for the periods indicated:

	Three Months Ended December 31,
	2015			2014

Propane revenues	$	188,930		$	396,248
Propane cost of sales	(170,558		)	(399,783		)
Propane product margin (loss)	$	18,372		$	(3,535	)

Propane sold (gallons)	348,511			380,528

Product margin per gallon (loss)	$	0.053		$	(0.009	)

Propane product margins per gallon of propane sold were higher during the three months ended December 31, 2015 than during the three months ended December 31, 2014. Prices declined during the three months ended December 31, 2015, but not as sharply as they declined during the three months ended December 31, 2014. Declining propane prices typically have an adverse affect on our margins.

We use a weighted-average inventory costing method for our wholesale propane inventory, with the costing pools segregated based on the location of the inventory. One of our business strategies is to purchase and store inventory during the warmer months for sale during the winter months. We seek to lock in a margin on inventory held in storage through back-to-back purchases and sales, fixed-price forward sale commitments, and financial derivatives. We also have contracts whereby we have committed to purchase ratable volumes each month at index prices. We seek to manage the price risk associated with these contracts primarily by selling the inventory immediately after it is received. When we sell product, we record the cost of the sale at the average cost of all inventory at that location, which may include inventory stored for sale in the future. During periods of rising prices, this can result in greater margins on these sales. During periods of declining prices, this can result in lower margins on these sales. We would generally expect the impact of these two different strategies being in the same inventory costing pools to even out over the course of a full fiscal year.

Our cost of sales of other products was $150.2 million during the three months ended December 31, 2015, as we sold 225.7 million gallons at an average cost of $0.67 per gallon. 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. During the three months ended December 31, 2014, our cost of sales of other products was $301.6 million, as we sold 230.3 million gallons at an average cost of $1.31 per gallon. Our cost of sales of other products during the three months ended December 31, 2014 was increased by $0.3 million of net unrealized losses on derivatives. The following table summarizes our per gallon product margin (in thousands, except per gallon amounts) for the periods indicated:

	Three Months Ended December 31,
	2015			2014

Other products revenues	$	180,620		$	329,943
Other products cost of sales	(150,203		)	(301,609		)
Other products product margin	$	30,417		$	28,334

Other products sold (gallons)	225,695			230,312

Product margin per gallon	$	0.135		$	0.123

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

Operating Expenses . Our liquids segment incurred operating expenses of $14.6 million during the three months ended December 31, 2015, compared to $7.3 million during the three months ended December 31, 2014. The increase was partially due to $1.2 million of expenses related to Sawtooth, which we acquired in February 2015, and an increase in compensation expense due primarily to a shift in the recording of incentive compensation expense related to bonuses from the liquids segment to “corporate and other” during the three months ended December 31, 2014. See further discussion within the “Corporate and Other” section below.

Loss on Disposal or Impairment of Assets, Net . Our liquids segment recorded losses on disposal of assets of $29.9 million during the three months ended December 31, 2014, which related primarily to the sale of a natural gas liquids terminal.

General and Administrative Expenses . Our liquids segment incurred general and administrative expenses of $1.7 million during the three months ended December 31, 2015, compared to $2.1 million during the three months ended December 31, 2014.

Depreciation and Amortization Expense . Our liquids segment incurred depreciation and amortization expense of $3.5 million during the three months ended December 31, 2015, compared to $2.8 million during the three months ended December 31, 2014. This increase was due primarily to $1.1 million of depreciation and amortization expense related to Sawtooth.

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,
	2015		2014		Change
	(in thousands)
Revenues:
Propane sales	$	68,880	$	99,859	$	(30,979	)
Distillate sales	19,133		29,102		(9,969		)
Other revenues	12,132		10,804		1,328
Total revenues	100,145		139,765		(39,620		)
Expenses:
Cost of sales—propane	27,471		54,712		(27,241		)
Cost of sales—distillates	14,198		23,015		(8,817		)
Cost of sales—other	4,305		3,445		860
Operating expenses	27,645		26,059		1,586
General and administrative expenses	2,980		3,108		(128		)
Depreciation and amortization expense	9,096		7,949		1,147
Total expenses	85,695		118,288		(32,593		)
Segment operating income	$	14,450	$	21,477	$	(7,027	)

Revenues . Our retail propane segment generated revenue of $68.9 million from propane sales during the three months ended December 31, 2015, selling 42.4 million gallons at an average price of $1.62 per gallon. During the three months ended December 31, 2014, our retail propane segment generated $99.9 million of revenue from propane sales, selling 48.3 million gallons at an average price of $2.07 per gallon. The decrease in volumes was due to significantly warmer temperatures during the quarter.

Our retail propane segment generated revenue of $19.1 million from distillate sales during the three months ended December 31, 2015, selling 9.1 million gallons at an average price of $2.10 per gallon. During the three months ended December 31, 2014, our retail propane segment generated $29.1 million of revenue from distillate sales, selling 9.4 million gallons at an average price of $3.10 per gallon. Distillate volumes were also adversely affected by the significantly warmer weather.

Cost of Sales . Our cost of retail propane sales was $27.5 million during the three months ended December 31, 2015, as we sold 42.4 million gallons at an average cost of $0.65 per gallon. During the three months ended December 31, 2014, our cost of retail propane sales was $54.7 million, as we sold 48.3 million gallons at an average cost of $1.13 per gallon. The following table summarizes our product margin for retail propane sales (in thousands, except per gallon amounts) for the periods indicated:

	Three Months Ended December 31,
	2015			2014

Propane revenues	$	68,880		$	99,859
Propane cost of sales	(27,471		)	(54,712		)
Propane product margin	$	41,409		$	45,147

Propane sold (gallons)	42,436			48,324

Product margin per gallon	$	0.976		$	0.934

Table of Contents

Our cost of distillate sales was $14.2 million during the three months ended December 31, 2015, as we sold 9.1 million gallons at an average cost of $1.56 per gallon. During the three months ended December 31, 2014, our cost of distillate sales was $23.0 million, as we sold 9.4 million gallons at an average cost of $2.45 per gallon. The following table summarizes our product margin for distillate sales (in thousands, except per gallon amounts) for the periods indicated:

	Three Months Ended December 31,
	2015			2014

Distillate revenues	$	19,133		$	29,102
Distillate cost of sales	(14,198		)	(23,015		)
Distillate product margin	$	4,935		$	6,087

Distillate sold (gallons)	9,102			9,381

Product margin per gallon	$	0.542		$	0.649

Operating Expenses . Our retail propane segment incurred operating expenses of $27.6 million during the three months ended December 31, 2015, compared to $26.1 million during the three months ended December 31, 2014. The increase was due primarily to increased compensation associated with acquisitions of retail propane businesses.

General and Administrative Expenses . Our retail propane segment incurred general and administrative expenses of $3.0 million during the three months ended December 31, 2015, compared to $3.1 million during the three months ended December 31, 2014.

Depreciation and Amortization Expense . Our retail propane segment incurred depreciation and amortization expense of $9.1 million during the three months ended December 31, 2015, compared to $7.9 million during the three months ended December 31, 2014. The increase was due primarily to acquisitions of retail propane businesses.

Refined Products and Renewables

The following table summarizes the operating results of our refined products and renewables segment for the periods indicated :

	Three Months Ended December 31,
	2015		2014 (1)		Change
	(in thousands)
Revenues:
Refined products sales (2)	$	1,532,928	$	1,831,243	$	(298,315	)
Renewables sales	101,414		126,812		(25,398		)
Service fees	32,381		25,993		6,388
Total revenues	1,666,723		1,984,048		(317,325		)
Expenses:
Cost of sales—refined products	1,503,358		1,788,100		(284,742		)
Cost of sales—renewables	91,253		117,525		(26,272		)
Operating expenses	24,887		27,985		(3,098		)
General and administrative expenses	4,030		11,692		(7,662		)
Depreciation and amortization expense	11,493		9,788		1,705
Total expenses	1,635,021		1,955,090		(320,069		)
Segment operating income	$	31,702	$	28,958	$	2,744

(1) During the three months ended September 30, 2015, we made certain changes in the way we attribute revenues and cost of sales to the categories shown in the table above. These changes did not impact total revenues or total cost of sales. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

(2) Revenues include $0.2 million and $0.6 million of intersegment sales during the three months ended December 31, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statement of operations.

Table of Contents

Revenues . Our refined products sales revenue was $1.5 billion during the three months ended December 31, 2015, selling 26.1 million barrels at an average price of $58.66 per barrel. Our refined products sales revenue was $1.8 billion during the three months ended December 31, 2014, selling 20.0 million barrels at an average price of $91.78 per barrel. The decrease in revenues was due primarily to a sharp decline in product prices, partially offset by higher sales volumes. The increase in volumes was due primarily to the purchase of certain pipeline capacity allocations from other shippers during the second half of the fiscal year ended March 31, 2015 and to expanded operations.

Our renewables sales revenue was $101.4 million during the three months ended December 31, 2015, selling 1.5 million barrels at an average price of $69.41 per barrel. Our renewables sales revenue was $126.8 million during the three months ended December 31, 2014, selling 1.4 million barrels at an average price of $87.58 per barrel.

Our refined products and renewables segment generated $32.4 million of service fee revenue during the three months ended December 31, 2015, compared to $26.0 million during the three months ended December 31, 2014. The increase was due primarily to the fact that one of TLP’s terminal facilities returned to service in November 2014, a one-time early asphalt contract termination settlement at various Gulf Coast terminals in November 2015, and the transfer of a contract obligation from NGL to a third party during the fiscal year ended March 31, 2015.

Cost of Sales . Our cost of refined products sales was $1.5 billion during the three months ended December 31, 2015, as we sold 26.1 million barrels at an average cost of $57.52 per barrel. Our cost of refined products sales was $1.8 billion during the three months ended December 31, 2014, as we sold 20.0 million barrels at an average cost of $89.62 per barrel. The following table summarizes our refined product margin (in thousands, except per barrel and per gallon amounts) for the periods indicated:

	Three Months Ended December 31,
	2015			2014

Refined products revenues	$	1,532,928		$	1,831,243
Refined products cost of sales	(1,503,358		)	(1,788,100		)
Refined products product margin	$	29,570		$	43,143

Refined products sold (barrels)	26,134			19,953

Product margin per barrel	$	1.131		$	2.162
Product margin per gallon	$	0.027		$	0.051

A significant portion of our refined product purchases and sales are priced based on a Gulf Coast index plus a specified differential. We use futures contracts with New York Harbor pricing to hedge the risk of price changes on our inventory valuation. Changes in the spreads between Gulf Coast and New York Harbor prices can impact the effectiveness of these futures contracts as hedges. During the three months ended December 31, 2015, Gulf Coast prices declined more than New York Harbor prices, and as a result, the futures contracts were less effective as hedges of our inventory valuation, which had an unfavorable impact on our product margins. We generally expect the spreads between the Gulf Coast and New York Harbor prices to be more consistent over the course of a year than during any individual quarter within the year. The tenor of these futures contracts, which are typically six months to one year in duration at inception, can also contribute to volatility in earnings among individual quarters within a fiscal year.

Table of Contents

Our cost of renewables sales was $91.3 million during the three months ended December 31, 2015, as we sold 1.5 million barrels at an average cost of $62.46 per barrel. Our cost of renewables sales was $117.5 million during the three months ended December 31, 2014, as we sold 1.4 million barrels at an average cost of $81.16 per barrel. The following table summarizes our renewables product margin (in thousands, except per barrel and per gallon amounts) for the periods indicated:

	Three Months Ended December 31,
	2015			2014

Renewables revenues	$	101,414		$	126,812
Renewables cost of sales	(91,253		)	(117,525		)
Renewables product margin	$	10,161		$	9,287

Renewable products sold (barrels)	1,461			1,448

Product margin per barrel	$	6.955		$	6.414
Product margin per gallon	$	0.166		$	0.153

Per-barrel product margins were higher during the three months ended December 31, 2015 than during the three months ended December 31, 2014 due primarily to an increase in the amount we can claim for certain biodiesel tax credits from $5.8 million for transactions during calendar year 2014 to $6.2 million for transactions in calendar year 2015.

Operating Expenses . Our refined products and renewables segment incurred operating expenses of $24.9 million during the three months ended December 31, 2015, compared to $28.0 million during the three months ended December 31, 2014. The decrease was due primarily to insurance proceeds received during the three months ended December 31, 2015 for certain environmental remediation matters.

General and Administrative Expenses . Our refined products and renewables segment incurred general and administrative expenses of $4.0 million during the three months ended December 31, 2015, compared to $11.7 million during the three months ended December 31, 2014. General and administrative expenses during the three months ended December 31, 2014 were increased by $6.0 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense . Our refined products and renewables segment incurred depreciation and amortization expense of $11.5 million during the three months ended December 31, 2015, compared to $9.8 million during the three months ended December 31, 2014.

Corporate and Other

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

	Three Months Ended December 31,
	2015			2014			Change
	(in thousands)
Incentive compensation expense	$	(2,994	)	$	(14,879	)	$	11,885
Acquisition expenses	(233		)	(665		)	432
Other corporate expenses	(9,692		)	(10,455		)	763
Total	$	(12,919	)	$	(25,999	)	$	13,080

The expenses shown in the table above for incentive compensation include cash-based and equity-based compensation. Such incentive compensation expenses were lower during the three months ended December 31, 2015 than during the three months ended December 31, 2014, due primarily to two factors described below.

As part of its review of our executive compensation program, the Compensation Committee of the Board of Directors approved a new type of equity-based compensation award in April 2015, under which the number of common units that vest is contingent upon the performance of our common units relative to the performance of other entities in the Alerian MLP Index. We re-value the unvested Performance Awards at each quarter end using a Monte Carlo simulation and adjust the amount of expense accordingly. As a result of a decline in the market value of our common units during the three months ended December 31, 2015, the fair value of the unvested

Table of Contents

Performance Awards has declined. During the three months ended December 31, 2015, we recorded a $1.8 million reduction to expense related to the Performance Awards.

We have also granted certain Service Awards, which vest contingent only on the continued service of the recipients. The expense associated with these Service Awards (exclusive of accruals of annual bonuses paid or expected to be paid in common units) was $0.4 million during the three months ended December 31, 2015, compared to $1.6 million during the three months ended December 31, 2014. We adjust our expense accruals for unvested Service Awards at each quarter end based on the market price of our common units, and the decline in the market value of our common units during the three months ended December 31, 2015 resulted in lower expense accruals for the Service Awards.

The expense associated with annual bonuses (a portion of which were paid or are expected to be paid in common units) was $4.4 million during the three months ended December 31, 2015, compared to $13.3 million during the three months ended December 31, 2014. The decrease in compensation expense was due to a shift in the recording bonus expenses from the individual business segments to “corporate and other” during the three months ended December 31, 2014. This shift in the recording of the bonus expense was due to an expectation that a portion of the bonuses would be paid in common units rather than cash. We record compensation expense related to common units within “corporate and other”, while compensation expense paid in cash is recorded within the individual business segments.

The expenses shown in the table above for acquisitions relate primarily to legal and advisory costs.

Segment Operating Results for the Nine Months Ended December 31, 2015 and 2014

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 expanded our liquids business through the February 2015 acquisition of Sawtooth. We expanded our retail propane business through numerous acquisitions of retail propane businesses. Our refined products and renewables businesses were significantly expanded with our July 2014 acquisition of TransMontaigne. 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 nine months ended December 31, 2015 are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2016.

Table of Contents

Volumes

The following table summarizes the volume of product sold and water received for the periods indicated. Volumes shown in the following table include intersegment sales.

	Nine Months Ended December 31,
Segment	2015	2014	Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)	55,911	63,295	(7,384	)

Water solutions
Water received (barrels)	164,843	112,752	52,091

Liquids
Propane sold (gallons)	820,127	804,520	15,607
Other products sold (gallons)	649,909	614,546	35,363

Retail propane
Propane sold (gallons)	89,938	95,466	(5,528	)
Distillates sold (gallons)	17,745	18,093	(348	)

Refined products and renewables
Refined products sold (barrels)	71,209	49,047	22,162
Renewable products sold (barrels)	4,144	3,938	206

Revenues and Cost of Sales by Segment

The following table summarizes our revenues and cost of sales by segment for the periods indicated:

	Nine Months Ended December 31,
	2015									2014
				Cost of			Product						Cost of			Product
	Revenues			Sales			Margin			Revenues			Sales			Margin
	(in thousands)
Crude oil logistics	$	2,862,870		$	2,778,323		$	84,547		$	5,761,506		$	5,704,896		$	56,610
Water solutions	147,225			(8,088		)	155,313			150,274			(27,951		)	178,225
Liquids	909,940			802,593			107,347			1,805,258			1,738,342			66,916
Retail propane	217,798			96,417			121,381			286,025			168,590			117,435
Refined products and renewables	5,336,085			5,149,867			186,218			5,708,765			5,570,789			137,976
Corporate and other	—			—			—			1,513			2,547			(1,034		)
Eliminations	(57,248		)	(57,235		)	(13		)	(132,055		)	(132,027		)	(28		)
Total	$	9,416,670		$	8,761,877		$	654,793		$	13,581,286		$	13,025,186		$	556,100

Table of Contents

Operating Income (Loss) by Segment

The following table summarizes our operating income (loss) by segment for the periods indicated:

	Nine Months Ended December 31,
Segment	2015			2014			Change
	(in thousands)
Crude oil logistics	$	12,689		$	(25,313	)	$	38,002
Water solutions	(8,645		)	48,390			(57,035		)
Liquids	52,820			(4,032		)	56,852
Retail propane	11,985			16,829			(4,844		)
Refined products and renewables	59,478			36,525			22,953
Corporate and other	(81,630		)	(67,105		)	(14,525		)
Operating income	$	46,697		$	5,294		$	41,403

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,
	2015		2014 (1)			Change
	(in thousands)
Revenues:
Crude oil sales	$	2,818,752	$	5,727,779		$	(2,909,027	)
Crude oil transportation and other	44,118		33,727			10,391
Total revenues (2)	2,862,870		5,761,506			(2,898,636		)
Expenses:
Cost of sales	2,778,323		5,704,896			(2,926,573		)
Operating expenses	35,537		38,487			(2,950		)
General and administrative expenses	6,225		13,835			(7,610		)
Depreciation and amortization expense	30,096		29,601			495
Total expenses	2,850,181		5,786,819			(2,936,638		)
Segment operating income (loss)	$	12,689	$	(25,313	)	$	38,002

(2) Revenues include $8.1 million and $26.2 million of intersegment sales during the nine months ended December 31, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues . Our crude oil logistics segment generated $2.8 billion of revenue from crude oil sales during the nine months ended December 31, 2015, selling 55.9 million barrels at an average price of $50.41 per barrel. During the nine months ended December 31, 2014, our crude oil logistics segment generated $5.7 billion of revenue from crude oil sales, selling 63.3 million barrels at an average price of $90.49 per barrel. The decrease in revenue per barrel was due primarily to the sharp decline in crude oil prices after September 30, 2014. The decrease in our sales volumes was due primarily to a slowdown in crude oil production and new drilling of crude oil in the current crude oil price environment.

Crude oil transportation and other revenues were $44.1 million during the nine months ended December 31, 2015, compared to $33.7 million during the nine months ended December 31, 2014. The increase was due primarily to crude oil markets being in contango during the nine months ended December 31, 2015 (a condition in which forward crude prices are greater than spot prices), which allowed us to generate revenue from leasing our owned storage and subleasing our leased storage.

Table of Contents

Cost of Sales . Our cost of crude oil sold was $2.8 billion during the nine months ended December 31, 2015, as we sold 55.9 million barrels at an average cost of $49.69 per barrel. Our cost of sales during the nine months ended December 31, 2015 was reduced by $3.2 million of net unrealized gains on derivatives and $6.1 million of net realized gains on derivatives. During the nine months ended December 31, 2014, our cost of crude oil sold was $5.7 billion, as we sold 63.3 million barrels at an average cost of $90.13 per barrel. Our cost of sales during the nine months ended December 31, 2014 was increased by $4.0 million of net unrealized losses on derivatives and was reduced by $26.8 million of net realized gains on derivatives. The following table summarizes our product margin for crude oil sales (in thousands, except per barrel amounts) for the periods indicated:

	Nine Months Ended December 31,
	2015			2014

Crude oil sales revenues	$	2,818,752		$	5,727,779
Crude oil cost of sales	(2,778,323		)	(5,704,896		)
Crude oil product margin	$	40,429		$	22,883

Crude oil sold (barrels)	55,911			63,295

Product margin per barrel	$	0.723		$	0.362

Per-barrel product margins were higher during the nine months ended December 31, 2015 than during the nine months ended December 31, 2014 due primarily to a lower of cost or market adjustment of $20.0 million recorded at December 31, 2014, partially offset by lower crude oil prices, which resulted in increased market pressure.

Operating Expenses . Our crude oil logistics segment incurred operating expenses of $35.5 million during the nine months ended December 31, 2015, compared to $38.5 million during the nine months ended December 31, 2014. The decrease was due primarily to lower incentive compensation expense.

General and Administrative Expenses . Our crude oil logistics segment incurred general and administrative expenses of $6.2 million during the nine months ended December 31, 2015, compared to $13.8 million during the nine months ended December 31, 2014. General and administrative expenses during the nine months ended December 31, 2014 included $5.6 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses were paid in December 2014. General and administrative expenses during the nine months ended December 31, 2014 were also increased by $1.3 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense . Our crude oil logistics segment incurred depreciation and amortization expense of $30.1 million during the nine months ended December 31, 2015, compared to $29.6 million during the nine months ended December 31, 2014.

Table of Contents

Water Solutions

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

	Nine Months Ended December 31,
	2015			2014			Change
	(in thousands)
Revenues:
Service fees	$	107,079		$	72,809		$	34,270
Recovered hydrocarbons	34,978			66,704			(31,726		)
Water transportation	—			10,761			(10,761		)
Other revenues	5,168			—			5,168
Total revenues	147,225			150,274			(3,049		)
Expenses:
Cost of sales—derivative gain (1)	(7,847		)	(34,207		)	26,360
Cost of sales—other	(241		)	6,256			(6,497		)
Operating expenses	94,035			70,736			23,299
Loss on disposal or impairment of assets, net	923			4,385			(3,462		)
General and administrative expenses	2,094			2,242			(148		)
Depreciation and amortization expense	66,906			52,472			14,434
Total expenses	155,870			101,884			53,986
Segment operating income (loss)	$	(8,645	)	$	48,390		$	(57,035	)

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

The following tables summarize activity separated between the following categories:

· facilities we owned before March 31, 2014, which we refer to below as “existing facilities”; and

· facilities we acquired or developed after March 31, 2014, 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:

	Nine Months Ended December 31,
	2015					2014
			Water	Fees Per				Water	Fees Per
	Service		Barrels	Water Barrel		Service		Barrels	Water Barrel
	Fees		Processed	Processed		Fees		Processed	Processed

Existing facilities	$	57,396	72,945	$	0.79	$	60,378	93,230	$	0.65
Recently acquired or developed facilities	49,683		91,898	0.54		12,431		19,522	0.64
Total	$	107,079	164,843	0.65		$	72,809	112,752	0.65

The decrease in the volume processed at our existing facilities during the nine months ended December 31, 2015 compared to the nine months ended December 31, 2014 was due primarily to a slowdown in customer production as a result of the lower crude oil prices, and was also due in part to migration of volumes from existing facilities to recently developed or acquired facilities due to the location of the 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:

	Nine Months Ended December 31,
	2015					2014
	Recovered		Water	Revenue Per		Recovered		Water	Revenue Per
	Hydrocarbon		Barrels	Water Barrel		Hydrocarbon		Barrels	Water Barrel
	Revenue		Processed	Processed		Revenue		Processed	Processed

Existing facilities	$	19,675	72,945	$	0.27	$	61,119	93,230	$	0.66
Recently acquired or developed facilities	15,303		91,898	0.17		5,585		19,522	0.29
Total	$	34,978	164,843	0.21		$	66,704	112,752	0.59

Water Transportation Revenues. Our water solutions segment generated $10.8 million of water transportation revenue during the nine months ended December 31, 2014. These revenues related to our water transportation business, which we sold during September 2014.

Other Revenues . Our water solutions segment generated $5.2 million of other revenues during the nine months ended December 31, 2015 relating to the disposal of solids.

Cost of Sales . We enter into derivatives in our water solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expected to recover when processing the wastewater. Our cost of sales during the nine months ended December 31, 2015 was reduced by $9.1 million of net realized gains on derivatives and was increased by $1.3 million of net unrealized losses on derivatives. Our cost of sales during the nine months ended December 31, 2014 was reduced by $12.1 million of net unrealized gains on derivatives and $22.1 million of net realized gains on derivatives. In December 2014, we settled derivative contracts that had scheduled settlement dates from April 2015 through September 2015, in order to lock in the gains on those derivatives.

Our other cost of sales was $6.3 million during the nine months ended December 31, 2014. These costs related primarily to our water transportation business, which we sold during September 2014.

Operating Expenses . The following table summarizes our operating expenses for the periods indicated:

	Nine Months Ended December 31,
	2015		2014		Change
	(in thousands)
Existing facilities	$	53,334	$	58,102	$	(4,768	)
Recently acquired or developed facilities	40,701		12,634		28,067
Total	$	94,035	$	70,736	$	23,299

The decrease in operating expenses for existing facilities was due primarily to lower operating costs of water disposal wells at existing facilities due to lower volumes processed.

Loss on Disposal or Impairment of Assets, Net . Our water solutions segment recorded $0.9 million of losses on disposal or impairment of assets during the nine months ended December 31, 2015 and recorded a loss of $4.4 million on disposal or impairment of assets during the nine months ended December 31, 2014. The loss recorded during the nine months ended December 31, 2014 was due primarily to a loss of $4.0 million related to the sale of our water transportation business during September 2014.

General and Administrative Expenses . Our water solutions segment incurred general and administrative expenses of $2.1 million during the nine months ended December 31, 2015, compared to $2.2 million during the nine months ended December 31, 2014.

Table of Contents

Depreciation and Amortization Expense . Our water solutions segment incurred depreciation and amortization expense of $66.9 million during the nine months ended December 31, 2015, compared to $52.5 million during the nine months ended December 31, 2014. Of the increase, $12.6 million related to recently acquired or developed facilities.

Liquids

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

	Nine Months Ended December 31,
	2015			2014 (1)			Change
	(in thousands)
Revenues:
Propane sales	$	393,442		$	859,984		$	(466,542	)
Other product sales	488,967			925,018			(436,051		)
Other revenues	27,531			20,256			7,275
Total revenues (2)	909,940			1,805,258			(895,318		)
Expenses:
Cost of sales—propane	375,831			854,421			(478,590		)
Cost of sales—other products	415,550			870,249			(454,699		)
Cost of sales—other	11,212			13,672			(2,460		)
Operating expenses	37,108			25,714			11,394
Loss (gain) on disposal or impairment of assets, net	(185		)	29,768			(29,953		)
General and administrative expenses	6,318			6,043			275
Depreciation and amortization expense	11,286			9,423			1,863
Total expenses	857,120			1,809,290			(952,170		)
Segment operating income (loss)	$	52,820		$	(4,032	)	$	56,852

(1) During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues and railcar cost of sales to the categories shown in the table above. These changes did not impact total revenues or total cost of sales. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

(2) Revenues include $48.4 million and $105.3 million of intersegment sales during the nine months ended December 31, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues . Our liquids segment generated $393.4 million of wholesale propane sales revenue during the nine months ended December 31, 2015, selling 820.1 million gallons at an average price of $0.48 per gallon. During the nine months ended December 31, 2014, our liquids segment generated $860.0 million of wholesale propane sales revenue, selling 804.5 million gallons at an average price of $1.07 per gallon. The increase in the volume sold was due primarily to the expansion of an agreement under which we market the majority of the production from a fractionation facility.

Our liquids segment generated $489.0 million of other wholesale products sales revenue during the nine months ended December 31 , 2015, selling 649.9 million gallons at an average price of $0.75 per gallon. During the nine months ended December 31, 2014, our liquids segment generated $925.0 million of other wholesale products sales revenue, selling 614.5 million gallons at an average price of $1.51 per gallon. The increase in the volume of other wholesale products sold was due to expanded operations.

Our liquids segment generated $27.5 million of other revenues during the nine months ended December 31, 2015, compared to $20.3 million during the nine months ended December 31, 2014. This revenue includes storage, terminaling and transportation services income. The increase was due primarily to $15.5 million of revenue related to Sawtooth, which we acquired in February 2015, partially offset by a $4.8 million decrease in hauling revenues due to declining market conditions.

Cost of Sales . Our cost of wholesale propane sales was $375.8 million during the nine months ended December 31, 2015, as we sold 820.1 million gallons at an average cost of $0.46 per gallon. Our cost of wholesale propane sales during the nine months ended December 31, 2015 was decreased by $0.6 million of net unrealized gains on derivatives. During the nine months ended December 31, 2014, our cost of wholesale propane sales was $854.4 million, as we sold 804.5 million gallons at an average cost of

Table of Contents

$1.06 per gallon. Our cost of wholesale propane sales during the nine months ended December 31, 2014 was increased by $8.1 million of net unrealized losses on derivatives. The following table summarizes our product margin for propane sales (in thousands, except per gallon amounts) for the periods indicated:

	Nine Months Ended December 31,
	2015			2014

Propane revenues	$	393,442		$	859,984
Propane cost of sales	(375,831		)	(854,421		)
Propane product margin	$	17,611		$	5,563

Propane sold (gallons)	820,127			804,520

Product margin per gallon	$	0.021		$	0.007

Propane product margins per gallon of propane sold were higher during the nine months ended December 31, 2015 than during the nine months ended December 31, 2014. Prices declined during the nine months ended December 31, 2015, but not as sharply as they declined during the nine months ended December 31, 2014. Declining propane prices typically have an adverse affect on our margins.

Our cost of sales of other products was $415.6 million during the nine months ended December 31, 2015, as we sold 649.9 million gallons at an average cost of $0.64 per gallon. 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. During the nine months ended December 31, 2014, our cost of sales of other products was $870.2 million, as we sold 614.5 million gallons at an average cost of $1.42 per gallon. Our cost of sales of other products during the nine months ended December 31, 2014 was reduced by $0.5 million of net unrealized gains on derivatives. The following table summarizes our per gallon product margin (in thousands, except per gallon amounts) for the periods indicated:

	Nine Months Ended December 31,
	2015			2014

Other products revenues	$	488,967		$	925,018
Other products cost of sales	(415,550		)	(870,249		)
Other products product margin	$	73,417		$	54,769

Other products sold (gallons)	649,909			614,546

Product margin per gallon	$	0.113		$	0.089

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

Operating Expenses . Our liquids segment incurred operating expenses of $37.1 million during the nine months ended December 31, 2015, compared to $25.7 million during the nine months ended December 31, 2014. The increase was due primarily to $3.4 million of expenses related to Sawtooth, which we acquired in February 2015, as well as a shift in the recording of incentive compensation expense related to bonuses from the liquids segment to “corporate and other” during the nine months ended December 31, 2014. See further discussion within the “Corporate and Other” section below.

Loss on Disposal or Impairment of Assets, Net . Our liquids segment incurred losses on disposal of assets of $29.8 million during the nine months ended December 31, 2014, which related primarily to the sale of a natural gas liquids terminal.

General and Administrative Expenses . Our liquids segment incurred general and administrative expenses of $6.3 million during the nine months ended December 31, 2015, compared to $6.0 million during the nine months ended December 31, 2014. The increase was due primarily to $1.0 million of expenses related to Sawtooth, which we acquired in February 2015.

Table of Contents

Depreciation and Amortization Expense . Our liquids segment incurred depreciation and amortization expense of $11.3 million during the nine months ended December 31, 2015, compared to $9.4 million during the nine months ended December 31, 2014. The increase was due to $3.8 million of expense during the nine months ended December 31, 2015 related to Sawtooth, which we acquired in February 2015, partially offset by $1.0 million of expense we recorded during the nine months ended December 31, 2014 related to a natural gas liquids terminal that we sold in December 2014.

Retail Propane

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

	Nine Months Ended December 31,
	2015		2014		Change
	(in thousands)
Revenues:
Propane sales	$	148,184	$	200,437	$	(52,253	)
Distillate sales	39,758		59,327		(19,569		)
Other revenues	29,856		26,261		3,595
Total revenues	217,798		286,025		(68,227		)
Expenses:
Cost of sales—propane	55,703		111,433		(55,730		)
Cost of sales—distillates	30,173		48,891		(18,718		)
Cost of sales—other	10,541		8,266		2,275
Operating expenses	73,901		68,746		5,155
General and administrative expenses	8,784		8,656		128
Depreciation and amortization expense	26,711		23,204		3,507
Total expenses	205,813		269,196		(63,383		)
Segment operating income	$	11,985	$	16,829	$	(4,844	)

Revenues . Our retail propane segment generated revenue of $148.2 million from propane sales during the nine months ended December 31, 2015, selling 89.9 million gallons at an average price of $1.65 per gallon. During the nine months ended December 31, 2014, our retail propane segment generated $200.4 million of revenue from propane sales, selling 95.5 million gallons at an average price of $2.10 per gallon. The decrease in volumes was due to significantly warmer temperatures and the decrease in selling price was due to lower commodity prices.

Our retail propane segment generated revenue of $39.8 million from distillate sales during the nine months ended December 31, 2015, selling 17.7 million gallons at an average price of $2.24 per gallon. During the nine months ended December 31, 2014, our retail propane segment generated $59.3 million of revenue from distillate sales, selling 18.1 million gallons at an average price of $3.28 per gallon.

Cost of Sales . Our cost of retail propane sales was $55.7 million during the nine months ended December 31, 2015, as we sold 89.9 million gallons at an average cost of $0.62 per gallon. During the nine months ended December 31, 2014, our cost of retail propane sales was $111.4 million, as we sold 95.5 million gallons at an average cost of $1.17 per gallon. The following table summarizes our product margin for retail propane sales (in thousands, except per gallon amounts) for the periods:

	Nine Months Ended December 31,
	2015			2014

Propane revenues	$	148,184		$	200,437
Propane cost of sales	(55,703		)	(111,433		)
Propane product margin	$	92,481		$	89,004

Propane sold (gallons)	89,938			95,466

Product margin per gallon	$	1.028		$	0.932

Table of Contents

Our cost of distillate sales was $30.2 million during the nine months ended December 31, 2015, as we sold 17.7 million gallons at an average cost of $1.70 per gallon. During the nine months ended December 31, 2014, our cost of distillate sales was $48.9 million, as we sold 18.1 million gallons at an average cost of $2.70 per gallon. The following table summarizes our product margin for distillate sales (in thousands, except per gallon amounts) for the periods indicated:

	Nine Months Ended December 31,
	2015			2014

Distillate revenues	$	39,758		$	59,327
Distillate cost of sales	(30,173		)	(48,891		)
Distillate product margin	$	9,585		$	10,436

Distillate sold (gallons)	17,745			18,093

Product margin per gallon	$	0.540		$	0.577

Operating Expenses . Our retail propane segment incurred operating expenses of $73.9 million during the nine months ended December 31, 2015, compared to $68.7 million during the nine months ended December 31, 2014. The increase was due primarily to increased compensation associated with acquisitions of retail propane businesses.

General and Administrative Expenses . Our retail propane segment incurred general and administrative expenses of $8.8 million during the nine months ended December 31, 2015, compared to $8.7 million during the nine months ended December 31, 2014.

Depreciation and Amortization Expense . Our retail propane segment incurred depreciation and amortization expense of $26.7 million during the nine months ended December 31, 2015, compared to $23.2 million during the nine months ended December 31, 2014. The increase was due primarily to acquisitions of retail propane businesses.

Refined Products and Renewables

The following table summarizes the operating results of our refined products and renewables segment for the periods indicated. Our refined products and renewables segment was significantly expanded with our July 2014 acquisition of TransMontaigne. The resultant increase in revenues and cost of sales was offset by a sharp decline in product prices.

	Nine Months Ended December 31,
	2015		2014 (1)		Change
	(in thousands)
Revenues:
Refined products sales (2)	$	4,946,136	$	5,283,855	$	(337,719	)
Renewables sales	300,756		374,911		(74,155		)
Service fees	89,193		49,999		39,194
Total revenues	5,336,085		5,708,765		(372,680		)
Expenses:
Cost of sales—refined products	4,859,519		5,207,580		(348,061		)
Cost of sales—renewables	290,348		363,209		(72,861		)
Operating expenses	76,288		59,447		16,841
General and administrative expenses	13,632		19,455		(5,823		)
Depreciation and amortization expense	36,820		22,549		14,271
Total expenses	5,276,607		5,672,240		(395,633		)
Segment operating income	$	59,478	$	36,525	$	22,953

(1) During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues and cost of sales to the categories shown in the table above. These changes did not impact total revenues or total cost of sales. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

(2) Revenues include $0.7 million and $0.6 million of intersegment sales during the nine months ended December 31, 2015, and 2014, respectively, that are eliminated in our condensed consolidated statement of operations.

Table of Contents

Revenues . Our refined products sales revenue was $4.9 billion during the nine months ended December 31, 2015, selling 71.2 million barrels at an average price of $69.46 per barrel. Our refined products sales revenue was $5.3 billion during the nine months ended December 31, 2014, selling 49.0 million barrels at an average price of $107.73 per barrel.

Our renewables sales revenue was $300.8 million during the nine months ended December 31, 2015, selling 4.1 million barrels at an average price of $72.58 per barrel. Our renewables sales revenue was $374.9 million during the nine months ended December 31, 2014, selling 3.9 million barrels at an average price of $95.20 per barrel.

Our refined products and renewables segment generated $89.2 million of service fee revenues during the nine months ended December 31, 2015, compared to $50.0 million during the nine months ended December 31, 2014. The increase was due primarily to the inclusion of TransMontaigne in the full nine months of the current fiscal year, compared to six months of the prior fiscal year.

Cost of Sales . Our cost of refined products sales was $4.9 billion during the nine months ended December 31, 2015, as we sold 71.2 million barrels at an average cost of $68.24 per barrel. Our cost of refined products sales was $5.2 billion during the nine months ended December 31, 2014, as we sold 49.0 million barrels at an average cost of $106.18 per barrel. The following table summarizes our refined product margin (in thousands, except per barrel and per gallon amounts) for the periods indicated:

	Nine Months Ended December 31,
	2015			2014

Refined products revenues	$	4,946,136		$	5,283,855
Refined products cost of sales	(4,859,519		)	(5,207,580		)
Refined products product margin	$	86,617		$	76,275

Refined products sold (barrels)	71,209			49,047

Product margin per barrel	$	1.216		$	1.555
Product margin per gallon	$	0.029		$	0.037

Our cost of renewables sales was $290.3 million during the nine months ended December 31, 2015, as we sold 4.1 million barrels at an average cost of $70.06 per barrel. Our cost of renewables sales was $363.2 million during the nine months ended December 31, 2014, as we sold 3.9 million barrels at an average cost of $92.23 per barrel. The following table summarizes our renewables product margin (in thousands, except per barrel and per gallon amounts) for the periods indicated:

	Nine Months Ended December 31,
	2015			2014

Renewables revenues	$	300,756		$	374,911
Renewables cost of sales	(290,348		)	(363,209		)
Renewables product margin	$	10,408		$	11,702

Renewable products sold (barrels)	4,144			3,938

Product margin per barrel	$	2.512		$	2.972
Product margin per gallon	$	0.060		$	0.071

Per-barrel product margins were lower during the nine months ended December 31, 2015 than during the nine months ended December 31, 2014 due primarily to lower renewables prices caused by increased import activity, partially offset by

Table of Contents

an increase in the amount we can claim for certain biodiesel tax credits from $5.8 million for transactions during calendar year 2014 to $6.2 million for transactions in calendar year 2015.

Operating Expenses . Our refined products and renewables segment incurred operating expenses of $76.3 million during the nine months ended December 31, 2015, compared to $59.4 million during the nine months ended December 31, 2014. The increase was due primarily to the inclusion of TransMontaigne in the full nine months of the current fiscal year, compared to six months of the prior fiscal year.

General and Administrative Expenses. Our refined products and renewables segment incurred general and administrative expenses of $13.6 million during the nine months ended December 31, 2015, compared to $19.5 million during the nine months ended December 31, 2014. General and administrative expenses during the nine months ended December 31, 2014 were increased by $7.5 million of compensation expense related to termination benefits for certain TransMontaigne employees. This decrease was partially offset by the inclusion of TransMontaigne in the full nine months of the current fiscal year, compared to six months of the prior fiscal year.

Depreciation and Amortization Expense . Our refined products and renewables segment incurred depreciation and amortization expense of $36.8 million during the nine months ended December 31, 2015, compared to $22.5 million during the nine months ended December 31, 2014. The increase was due primarily to depreciation on TLP’s terminal assets and amortization of customer relationship intangible assets acquired in the business combination with TransMontaigne. TLP accounted for $34.1 million and $16.7 million of depreciation and amortization expense during the nine months ended December 31, 2015 and 2014, respectively.

Corporate and Other

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

	Nine Months Ended December 31,
	2015			2014			Change
	(in thousands)
Incentive compensation expense	$	(54,286	)	$	(37,089	)	$	(17,197	)
Acquisition expenses	(864		)	(4,993		)	4,129
Other corporate expenses	(26,480		)	(25,023		)	(1,457		)
Total	$	(81,630	)	$	(67,105	)	$	(14,525	)

The expenses shown in the table above for incentive compensation include cash-based and equity-based compensation. Such incentive compensation expenses were higher during the nine months ended December 31, 2015 than during the nine months ended December 31, 2014, due primarily to two factors described below.

As part of its review of our executive compensation program, the Compensation Committee of the Board of Directors approved a new type of equity-based compensation award, under which the number of common units that vest is contingent upon the performance of our common units relative to the performance of other entities in the Alerian MLP Index. During the nine months ended December 31, 2015, three tranches of these Performance Awards were granted, with vesting dates of July 1, 2015, July 1, 2016, and July 1, 2017, respectively. We recorded $16.3 million of expense related to the Performance Awards during the nine months ended December 31, 2015, $16.1 million of which related to awards that vested on July 1, 2015.

We have also granted certain Service Awards, which vest contingent only on the continued service of the recipients. The number of outstanding Service Awards was higher at December 31, 2015 than at December 31, 2014. This was due in part to the addition of new employees as our business has expanded, and was due in part to increases in the number of Service Awards granted to certain employees following the Compensation Committee’s review of our compensation program. The expense associated with these Service Awards (exclusive of accruals of annual bonuses paid or expected to be paid in common units) was $22.0 million during the nine months ended December 31, 2015, compared to $12.8 million during the nine months ended December 31, 2014.

The expense associated with annual bonuses (a portion of which were paid or are expected to be paid in common units) was $16.0 million during the nine months ended December 31, 2015, compared to $24.3 million during the nine months ended December 31, 2014. We record compensation expense related to common units within “corporate and other”, while compensation expense paid in cash is recorded within the individual business segments.

The expenses shown in the table above for acquisitions relate primarily to legal and advisory costs. We incurred $3.7 million of such expenses during the nine months ended December 31, 2014 related to our acquisition of TransMontaigne.

Table of Contents

Equity in Earnings of Unconsolidated Entities

Equity in earnings of unconsolidated entities was $2.9 million during the three months ended December 31, 2015, compared to $1.2 million during the three months ended December 31, 2014. The increase was due primarily to an increase of $2.4 million in earnings from our investments in Glass Mountain, BOSTCO, and Frontera , partially offset by a decrease of $0.7 million in earnings from our investments in an ethanol production facility and a water supply company.

Equity in earnings of unconsolidated entities was $14.0 million during the nine months ended December 31, 2015, compared to $7.5 million during the nine months ended December 31, 2014. The increase was due primarily to an increase of $8.1 million of earnings from BOSTCO and Frontera that we acquired as part of our July 2014 acquisition of TransMontaigne, partially offset by a decrease of $1.8 million in earnings from our investments in an ethanol production facility and a water supply company.

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 noninterest bearing debt obligations. Interest expense was $36.2 million during the three months ended December 31, 2015, compared to $30.1 million during the three months ended December 31, 2014. The increase in interest expense was due primarily to the increased level of debt outstanding on our Revolving Credit Facility (hereinafter defined) (the average balance outstanding on our Revolving Credit Facility was $1.9 billion during the three months ended December 31, 2015, compared to $1.3 billion during three months ended December 31, 2014), primarily to finance acquisitions and capital expenditures.

Interest expense was $98.5 million during the nine months ended December 31, 2015, compared to $79.2 million during the nine months ended December 31, 2014. The increase in interest expense was due primarily to (i) the increased level of debt outstanding on our Revolving Credit Facility (the average balance outstanding on our Revolving Credit Facility was $1.7 billion during the nine months ended December 31, 2015, compared to $1.1 billion during nine months ended December 31, 2014), primarily to finance acquisitions and capital expenditures; (ii) the issuance of $400.0 million of fixed-rate notes during July 2014, which bear a higher interest rate than our Revolving Credit Facility; and (iii) increased interest expense related to TLP’s credit facility (our interest in TLP was acquired in July 2014).

Other Income, Net

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

	Three Months Ended December 31,						Nine Months Ended December 31,
	2015			2014			2015			2014
	(in thousands)
Interest income (1)	$	2,722		$	1,547		$	9,422		$	2,771
Crude oil marketing arrangement (2)	(551		)	(704		)	(6,386		)	(4,451		)
Other (3)	(10		)	2,528			(95		)	4,043
Other income, net	$	2,161		$	3,371		$	2,941		$	2,363

(1) Relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility being used by a third party and to a loan receivable from an equity method investee.

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

(3) Includes $2.5 million of income related to the settlement of a contractual dispute during the three and nine months ended December 31, 2014.

Income Tax Expense (Benefit)

Table of Contents

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.

Income tax expense was $0.4 million during the three months ended December 31, 2015, compared to an income tax benefit of $2.1 million during the three months ended December 31, 2014. TransMontaigne was a taxable subsidiary from July 1, 2014 (the date we acquired TransMontaigne) to December 30, 2014 (the date we converted TransMontaigne to a non-taxable entity). Income tax benefit during the three months ended December 31, 2014 was attributable primarily to TransMontaigne.

Income tax benefit was $1.8 million during the nine months ended December 31, 2015, compared to $3.0 million during the nine months ended December 31, 2014. TransMontaigne was a taxable subsidiary from July 1, 2014 (the date we acquired TransMontaigne) to December 30, 2014 (the date we converted TransMontaigne to a non-taxable entity). Income tax benefit during the nine months ended December 31, 2015 includes a benefit of $3.6 million related to a change in estimate of the income tax obligation payable related to TransMontaigne. Income tax benefit during the nine months ended December 31, 2014 was attributable primarily to TransMontaigne.

Noncontrolling Interests

Net income attributable to noncontrolling interests was $6.1 million during the three months ended December 31, 2015, compared to $5.6 million during the three months ended December 31, 2014.

Net income attributable to noncontrolling interests was $12.9 million during the nine months ended December 31, 2015, compared to $9.1 million during the nine months ended December 31, 2014. The increase was due primarily to the July 2014 acquisition of TransMontaigne, in which we acquired a 2% general partner interest and a 19.7% limited partner interest in TLP.

Seasonality

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

Liquidity, Sources of Capital and Capital Resource Activities

Our principal sources of liquidity and capital are the cash flows from our operations and borrowings under our Revolving Credit Facility. 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. TLP’s partnership agreement also requires that, within 45 days after the end of each quarter, it distribute all of its available cash (as defined in its partnership agreement) to its unitholders as of the record date.

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.

We have historically pursued a strategy of growth through acquisitions. Under current market conditions, the cost of capital is much higher than it has been in recent years; prospective lenders seek much higher interest rates than they have sought in the past, and at our current distribution level the yield on our common units is much higher than it has been in the past. Under these 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 construction of the Grand Mesa Pipeline and the continued development of Sawtooth natural gas liquids storage caverns, 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. We intend to continue to pay a quarterly distribution at the current level of $0.64 per quarter, although we do not expect to increase the amount of the quarterly distribution in the near term.

Credit Agreement

The Expansion Capital Facility had a total capacity of $1.436 billion for cash borrowings at December 31, 2015. At that date, we had outstanding borrowings of $1.317 billion 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, 2015. At that date, we had outstanding borrowings of $603.5 million and outstanding letters of credit of $117.1 million on the Working Capital Facility. Amounts outstanding for letters of credit are not recorded as long-term debt on our 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.

At December 31 , 2015, we were in compliance with the covenants under the Credit Agreement.

Table of Contents

2019 Notes

At December 31, 2015, we were in compliance with the covenants under the indenture governing the 2019 Notes.

2021 Notes

At December 31, 2015, we were in compliance with the covenants under the indenture governing the 2021 Notes.

2022 Notes

The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create or permit certain liens, (iv) create or permit restrictions on the ability of certain of our subsidiaries to pay dividends or make other distributions to us, (v) enter into transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate, merge, or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains similar leverage ratio and interest coverage ratio requirements to those of our Credit Agreement described above. In December 2015, we amended the Note Purchase Agreement to change the covenants to mirror the changes made to the covenants in our Credit Agreement. In addition, we agreed to pay an additional 0.5% per year in interest if our leverage ratio exceeds 4.25 to 1.

At December 31, 2015, we were in compliance with the covenants under the Note Purchase Agreement.

Table of Contents

TLP Credit Facility

TLP is party to a credit agreement with a syndicate of banks that provides for a revolving credit facility (the “TLP Credit Facility”). The TLP Credit Facility provides for a maximum borrowing line of credit equal to the lesser of (i) $400 million or (ii) 4.75 times Consolidated EBITDA (as defined in the TLP Credit Facility). The terms of the TLP Credit Facility include covenants that restrict TLP’s ability to make cash distributions, acquisitions and investments, including investments in joint ventures. TLP may make distributions of cash to the extent of TLP’s “available cash” (as defined in TLP’s partnership agreement) . TLP may make acquisitions and investments that meet the definition of “permitted acquisitions,” “other investments” which may not exceed 5% of “consolidated net tangible assets,” and additional future “permitted JV investments” up to $125 million, which may include additional investments in BOSTCO. The commitments under the TLP Credit Facility mature on July 31, 2018.

The TLP Credit Facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the TLP Credit Facility are (i) a total leverage ratio test (not to exceed 4.75 times), (ii) a senior secured leverage ratio test (not to exceed 3.75 times) if TLP issues senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times). These financial covenants are based on “Consolidated EBITDA” (as defined in the TLP Credit Facility) . The TLP Credit Facility is non-recourse to the Partnership. At December 31, 2015, TLP was in compliance with the covenants under the TLP Credit Facility.

Cash and cash equivalents	$	681
Accounts receivable—trade	5,974
Accounts receivable—affiliates	515
Inventories	1,411
Prepaid expenses and other current assets	999
Property, plant and equipment, net	474,331
Goodwill	30,169
Intangible assets, net	60,409
Investments in unconsolidated entities	254,516
Other noncurrent assets	674
Accounts payable—trade	(7,895		)
Accounts payable—affiliates	(153		)
Net intercompany payable	(1,632		)
Accrued expenses and other payables	(8,584		)
Advanced payments received from customers	(151		)
Long-term debt	(248,000		)
Other noncurrent liabilities	(2,731		)
Net assets	$	560,533

Table of Contents

Revolving Credit Balances

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

	Average
	Daily		Lowest		Highest
	Outstanding		Balance		Balance
	(in thousands)
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

Nine Months Ended December 31, 2014
Expansion capital borrowings	$	350,284	$	114,000	$	620,000
Working capital borrowings	732,340		339,500		1,046,000
TLP credit facility borrowings	249,060		228,000		259,700

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)	2015			2014
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	119,539		$	(92,557	)
Changes in operating assets and liabilities	173,595			174,397

Operating activities	$	293,134		$	81,840

Investing activities	(595,101		)	(1,114,502		)

Financing activities	285,843			1,052,778

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 general, our operating cash flows are at their lowest levels during our first and second fiscal quarters, or the six months ending September 30, when we experience operating losses or lower operating income as a result of lower volumes of natural gas liquids sales and when we are building our inventory levels for the upcoming heating season. Our operating cash flows are generally greatest during our third and fourth fiscal quarters, or the six months ending March 31, when our operating income levels are highest and customers pay for natural gas liquids consumed during the heating season months. We borrow under our Revolving Credit Facility to supplement our operating cash flows as necessary during our first and second fiscal quarters.

Investing Activities . Net cash used in investing activities was $595.1 million during the nine months ended December 31, 2015, compared to $1.1 billion during the nine months ended December 31, 2014. The decrease in net cash used in investing activities was due primarily to a $926.7 million decrease in cash paid for acquisitions during the nine months ended December 31, 2015 as cash paid for acquisitions during the nine months ended December 31, 2014 included $580.7 million for the acquisition of TransMontaigne. This decrease was partially offset by:

· an increase in capital expenditures from $135.4 million during the nine months ended December 31, 2014, $106.9 million of which was expansion capital (of this expansion capital, $3.7 million related to TLP) and $28.5 million of which was maintenance capital (of this maintenance capital, $2.0 million related to TLP), to $372.1 million during the nine months ended December 31, 2015, $333.0 million of which was expansion capital (of this expansion capital, $10.4

Table of Contents

million related to TLP) and $39.1 million of which was maintenance capital (of this maintenance capital, $11.4 million related to TLP);

· a $125.0 million increase due to the purchase of a 37.5% undivided interest in a crude oil pipeline from Colorado to Oklahoma (see “Recent Developments”) during the nine months ended December 31, 2015; and

· a $98.2 million decrease in cash flows from derivatives.

Financing Activities . Net cash provided by financing activities was $285.8 million during the nine months ended December 31, 2015, compared to $1.1 billion during the nine months ended December 31, 2014. The decrease in net cash provided by financing activities was due primarily to:

· $400.0 million in proceeds received from the issuance of the 2019 Notes during the nine months ended December 31, 2014;

· $370.4 million in proceeds received from the sale of our common units during the nine months ended December 31, 2014; and

· a $71.5 million increase in distributions paid to our partners and noncontrolling interest owners during the nine months ended December 31, 2015.

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

			Amount		Amount Paid To		Amount Paid To
Date Declared	Record Date	Date Paid	Per Unit		Limited Partners		General Partner
					(in thousands)		(in thousands)
April 24, 2014	May 5, 2014	May 15, 2014	$	0.5513	$	43,737	$	5,754
July 24, 2014	August 4, 2014	August 14, 2014	0.5888		52,036		9,481
October 24, 2014	November 4, 2014	November 14, 2014	0.6088		53,902		11,141
January 26, 2015	February 6, 2015	February 13, 2015	0.6175		54,684		11,860
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		66,244		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		67,303		16,277

The following table summarizes distributions declared by TLP after our acquisition of general and limited partner interests in TLP (exclusive of the distribution declared in July 2014, the proceeds of which we remitted to the former owners of TransMontaigne, pursuant to agreements entered into at the time of the business combination):

							Amount Paid To
Date Declared	Record Date	Date Paid	Amount Per Unit		Amount Paid To NGL		Noncontrolling Interest Owners
					(in thousands)		(in thousands)
October 13, 2014	October 31, 2014	November 7, 2014	$	0.6650	$	4,010	$	8,614
January 8, 2015	January 30, 2015	February 6, 2015	0.6650		4,010		8,614
April 13, 2015	April 30, 2015	May 7, 2015	0.6650		4,007		8,617
July 13, 2015	July 31, 2015	August 7, 2015	0.6650		4,007		8,617
October 12, 2015	October 30, 2015	November 6, 2015	0.6650		4,007		8,617
January 19, 2016	January 29, 2016	February 8, 2016	0.6700		4,104		8,681

Common Unit Repurchase Program

Table of Contents

Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2015 for our fiscal years ending thereafter:

			Three Months
			Ending
			March 31,		Year Ending March 31,
	Total		2016		2017		2018		2019		2020		Thereafter
	(in thousands)
Principal payments on long-term debt—
Expansion capital borrowings	$	1,317,000	$	—	$	—	$	—	$	1,317,000	$	—	$	—
Working capital borrowings	603,500		—		—		—		603,500		—		—
2019 Notes	400,000		—		—		—		—		400,000		—
2021 Notes	450,000		—		—		—		—		—		450,000
2022 Notes	250,000		—		—		25,000		50,000		50,000		125,000
TLP Credit Facility	248,000		—		—		—		248,000		—		—
Other long-term debt	62,592		1,016		7,263		7,056		6,581		5,959		34,717
Interest payments on long-term debt—
Revolving Credit Facility (1)	156,928		13,697		55,089		55,089		33,053		—		—
2019 Notes	82,000		10,250		20,500		20,500		20,500		10,250		—
2021 Notes	185,625		—		30,938		30,938		30,938		30,938		61,873
2022 Notes	70,656		4,156		16,625		16,209		13,300		9,975		10,391
TLP Credit Facility	17,996		2,249		6,746		6,746		2,255		—		—
Other long-term debt	14,945		733		3,725		3,311		2,899		2,515		1,762
Letters of credit	117,117		—		—		—		117,117		—		—
Future minimum lease payments under noncancelable operating leases	443,439		28,264		100,606		85,570		61,645		52,043		115,311
Future minimum throughput payments under noncancelable agreements (2)	320,706		14,156		56,684		56,770		55,978		46,146		90,972
Construction commitments (3)	135,659		94,177		41,482		—		—		—		—
Fixed-price commodity purchase commitments (4)	60,701		57,276		3,425		—		—		—		—
Index-price commodity purchase commitments (5)	713,695		648,101		65,594		—		—		—		—
Total contractual obligations	$	5,650,559	$	874,075	$	408,677	$	307,189	$	2,562,766	$	607,826	$	890,026

Purchase commitments (thousands):
Natural gas liquids fixed-price (gallons) (6)	25,653		18,695		6,958		—		—		—		—
Natural gas liquids index-price (gallons) (6)	406,147		261,117		145,030		—		—		—		—
Crude oil fixed-price (barrels) (6)	1,075		1,075		—		—		—		—		—
Crude oil index-price (barrels) (6)	21,371		21,371		—		—		—		—		—

(1) The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at December 31, 2015. See Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report for additional information on our Credit Agreement.

(2) At December 31, 2015, we had agreements with crude oil and refined products pipeline operators obligating us to minimum throughput payments in exchange for pipeline capacity commitments.

(3) At December 31, 2015, we had the following construction commitments:

· In November 2015, we reached an agreement with Saddlehorn to jointly construct, own and operate a crude oil pipeline. At December 31, 2015, our share of the remaining total construction costs for this pipeline is approximately $125 million. Construction of the joint pipeline is expected to be completed in August 2016, with service beginning during the fourth quarter of calendar year 2016.

· In February 2015, we acquired Sawtooth, which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets. As part of this acquisition, we also entered into a construction agreement to expand the storage capacity of the facility. We anticipate this project will be completed by the end of

Table of Contents

the second calendar quarter of 2016. At December 31, 2015, the construction commitments for this project were $10.7 million.

(4) At December 31, 2015, we had the following purchase commitments (in thousands):

Natural gas liquids fixed-price		$	14,506
Crude oil fixed-price		46,195

(5) At December 31, 2015, we had the following purchase commitments (in thousands):

Natural gas liquids index-price		$	167,396
Crude oil index-price		546,299

Index prices are based on a forward price curve at December 31 , 2015. A theoretical change of $0.10 per gallon in the underlying commodity price at December 31 , 2015 would result in a change of $40.6 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 , 2015 would result in a change of $21.4 million in the value of our index-price crude oil purchase commitments.

(6) At December 31, 2015, we had the following sales contract volumes (in thousands):

Natural gas liquids fixed-price (gallons)		146,488
Natural gas liquids index-price (gallons)		267,468
Crude oil fixed-price (barrels)		2,093
Crude oil index-price (barrels)		21,331

Off-Balance Sheet Arrangements

We do not have any off balance sheet arrangements other than the operating leases described in Note 11 to our condensed consolidated financial statements included in this Quarterly Report.

Environmental Legislation

Please 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.

Trends

Crude oil prices can fluctuate widely based on changes in supply and demand conditions. The opportunity to generate revenues in our crude oil logistics business is heavily influenced by the volume of crude oil being produced. Crude oil prices declined sharply during the period from July 2014 through December 2015 (the spot price for NYMEX West Texas Intermediate crude oil at Cushing, Oklahoma declined from $105.34 per barrel at July 1, 2014 to $37.04 per barrel at December 31, 2015). While crude oil production in the United States has been strong in recent years, the sharp decline in crude oil prices has reduced the incentive for producers to expand production. If crude oil prices remain low, resultant declines in crude oil production may adversely impact volumes in our crude oil logistics business.

Since January 2015, crude oil markets have been in contango (a condition in which the forward crude price is higher that the spot price). Our crude oil logistics business benefits when the market is in contango, as higher forward prices result in inventory holding gains between the time we financially hedge a barrel in inventory and physically sell the same barrel. In addition, we are able to better use our storage assets when crude oil markets are in contango.

Our opportunity to generate revenues in our water solutions business is based on the level of production of natural gas and crude oil in the areas where our facilities are located. As described above, crude oil prices declined sharply during the year ended March 31, 2015. At current market prices, producers may reduce drilling activity, which could have an adverse impact on the volumes of our water solutions business. A portion of the revenues of our water solutions business is generated from the sale of hydrocarbons

Table of Contents

that we recover when processing the wastewater. Because of this, lower crude oil prices result in lower per-barrel revenues for our water solutions business.

An important element of our refined products and renewables segment relates to the marketing of refined products in the Southeast and East Coast regions. We purchase product in the Gulf Coast, transport the product on third party pipelines, and sell the product primarily at TLP’s refined products terminals. Most of the contracts with these customers are one year in duration, with pricing indexed to prices in the Gulf Coast at the date of sale plus a specified differential. To operate this business we maintain inventory in transit on the third party pipelines and at the destination terminals where we sell the product. The value of this inventory will increase or decrease as market prices change. In order to mitigate this risk, we enter into futures contracts, which are only available based on New York Harbor pricing. Because our contracts are indexed to Gulf Coast prices and our futures contracts are based on New York Harbor prices, the futures contracts are not a perfect hedge against our inventory holding risk. During any given quarter, spreads between prices in the Gulf Coast and New York Harbor could narrow or widen, which could reduce the effectiveness of the futures contracts as a hedge of the inventory holding risk. The tenor of these futures contracts, which are typically six months to one year in duration at inception, can also contribute to volatility in earnings among individual quarters within a fiscal year.

During the three months ended December 31, 2015, prices for refined products declined. Gulf Coast prices, on which our sales contracts are based, declined more than the New York Harbor prices, on which our futures contracts are based, which had an adverse impact on our weighted-average cost of sales. Based on historical experience, we generally expect the spreads between Gulf Coast and New York Harbor prices to be more consistent over the course of a contract year than during any individual quarter within the year, and that we should expect more volatility in weighted-average cost of sales among quarters within a fiscal year than we would expect during a full fiscal year.

The decline in crude oil prices has had an adverse impact on many participants in the energy markets, and the inherent risk of customer or counterparty nonperformance is higher when crude oil prices are low or in decline.

Recent Accounting Pronouncements

In July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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, 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 operation.

In April 2015, the FASB issued ASU No. 2015 —03, “Simplifying the Presentation of Debt Issuance Costs.” The ASU requires that debt issuance costs (excluding costs associated with revolving debt arrangements) be presented in the balance sheet as a reduction to the carrying amount of the debt. We plan to adopt this ASU effective March 31, 2016, when we will begin presenting debt issuance costs as a reduction to long-term debt, rather than as an intangible asset. At December 31, 2015, intangible assets on our condensed consolidated balance sheet include $17.4 million of debt issuance costs associated with our senior notes that, upon adoption of this ASU, would be reclassified as a reduction to long-term debt. The ASU requires retrospective application for all prior periods presented. At March 31, 2015, intangible assets on our condensed consolidated balance sheet include $17.8 million of debt issuance costs associated with our senior notes that, upon adoption of this ASU, will be reclassified as a reduction to long-term debt.

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

Critical Accounting Policies

The preparation of financial statements and related disclosures in 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 the following accounting policies that are most important to the portrayal of our financial condition and results of operations. The application of these accounting policies, which requires subjective or complex 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.

Table of Contents

Revenue Recognition

Impairment of Long-Lived Assets

Goodwill is subject to at least an annual assessment for impairment. We perform our annual assessment of impairment during the fourth quarter of our fiscal year, and more frequently if circumstances warrant. To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting unit exceeds its carrying amount. The assessment of the value of our reporting units requires us to make certain assumptions relating to future operations. When evaluating operating performance, various factors are considered, such as current and changing economic conditions and the commodity price environment, among others. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge.

Crude oil prices began declining in July 2014 and continued to decline during calendar year 2015. Low crude oil prices have had an unfavorable impact on our water solutions business, as the volume of water we process is driven in part by the level of crude oil production, and the lower crude oil prices have given producers less incentive to expand production. In addition, a portion of the revenues of our water solutions business are generated from the sale of crude oil that we recover in the process of treating the wastewater, and low crude oil prices have an adverse impact on these revenues.

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

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

Table of Contents

Asset Retirement Obligations

We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value can be made. In order to determine the fair value of such a liability, we must make certain estimates and assumptions including, among other things, projected cash flows, the estimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time. Our condensed consolidated balance sheet at December 31, 2015 includes a liability of $5.0 million related to asset retirement obligations, which is reported within other noncurrent liabilities. This liability is related to 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.

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

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

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

Amortization of Intangible Assets

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

Tank Bottoms

Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost within property, plant and equipment on our condensed consolidated balance sheets. We recover tank bottoms when the storage tanks are removed from service. The following table summarizes the tank bottoms reported in our condensed consolidated balance sheet at December 31, 2015:

	Volume
Product	(in barrels)	Value
	(in thousands)
Gasoline	230	$	26,906
Crude oil	231	19,349
Diesel	113	13,697
Renewables	28	2,906
Other	12	708
Total		$	63,566

Table of Contents

Linefill

We have entered into long-term commitments to ship specified minimum volumes of crude oil on certain third-party owned pipelines. These agreements require that we maintain a certain minimum amount of crude oil in the pipeline to serve as linefill over the duration of the agreement. We report such linefill at historical cost within other noncurrent assets on our condensed consolidated balance sheets. At December 31, 2015, linefill was $35.1 million and consisted of 487,104 barrels of crude oil.

Business Combinations

We record business combinations using the “acquisition method,” in which the assets acquired and liabilities assumed are recorded at their acquisition date fair values. Fair values of assets acquired and liabilities assumed are based upon available information and may involve engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identify and include in the allocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property, plant and equipment and intangible assets, including those with indefinite lives. The estimates also include the fair value of contracts including commodity purchase and sale agreements, storage contracts, and transportation contracts. The excess of the purchase price over the net fair value of acquired assets and assumed liabilities is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Pursuant to GAAP, an entity is allowed no more than one year to obtain the information necessary to identify and measure the fair values of the assets acquired and liabilities assumed in a business combination. The impact of subsequent changes to the identification of assets and liabilities may require retrospective adjustments to our previously reported consolidated financial position and results of operations.

Inventories

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

Equity-Based Compensation

Our general partner has granted certain restricted units to employees and directors under a long-term incentive plan. Awards granted under the long-term incentive plan include restricted units that vest contingent on the continued service of the recipients through the vesting date (the “Service Awards”). Awards also include restricted units that are contingent upon both 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 over specified periods of time (the “Performance Awards”). The awards may also vest in the event of a change in control, at the discretion of the board of directors.

Table of Contents

recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using a Monte Carlo simulation.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

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

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, 2015, we had $1.92 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 2.68%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $2.4 million, based on borrowings outstanding at December 31, 2015.

The TLP Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At December 31, 2015, TLP had $248.0 million of outstanding borrowings under the TLP Credit Facility at a rate of 2.72%. A change in interest rates of 0.125% would result in an increase or decrease in TLP’s annual interest expense of $0.3 million, based on borrowings outstanding at December 31, 2015.

Commodity Price and Credit Risk

Our operations are subject to certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that the market value of crude oil, natural gas liquids, and refined products will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract.

Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. 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, 2015, 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.

100

Table of Contents

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, 2015 fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands):

	Increase
	(Decrease)
	To Fair Value
Crude oil (crude oil logistics segment)	$	(4,707	)
Crude oil (water solutions segment)	(1,049		)
Propane (liquids segment)	657
Other products (liquids segment)	(195		)
Refined products (refined products and renewables segment)	(15,276		)
Renewables (refined products and renewables segment)	(8,869		)
Other Canadian dollars (liquids segment)	894

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, 2015. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of December 31, 2015, such disclosure controls and procedures were effective to provide the reasonable assurance described above.

Other than changes that have resulted or may result from our acquisition of TransMontaigne, as discussed below, there have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)—15(f) of the Exchange Act) during the three months ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

We acquired TransMontaigne and certain related operations in July 2014, as described in Note 5 to our condensed consolidated financial statements included in this Quarterly Report. At this time, we continue to evaluate the business and internal controls and processes associated with TransMontaigne and are making various changes to its operating and organizational structure based on our business plan. We are in the process of implementing our internal control structure over this acquired business. We expect that our evaluation and integration efforts related to these operations will continue into future fiscal quarters.

101

Table of Contents

PART II

Item 1. Legal Proceedings

For information related to legal proceedings, please see the discussion under the caption “Legal Contingencies” in Note 11 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.

The U.S. Environmental Protection Agency (“EPA”) has informed NGL Crude Logistics, LLC (“NGL Crude”; formerly known as Gavilon, LLC (“Gavilon Energy”) prior to its acquisition by us in December 2013) of alleged violations in 2011 by Gavilon Energy of the Clean Air Act’s renewable fuel standards regulations. The EPA’s allegations relate to transactions between Gavilon Energy and one of its suppliers and the generation of biodiesel renewable identification numbers sold by such supplier to Gavilon Energy in 2011. We have vigorously denied the allegations. In an effort to resolve this matter, the parties have recently commenced settlement negotiations, which are ongoing.

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 year ended March 31, 2015.

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

Common Unit Repurchase Program

On September 10, 2015, the Board of Directors of our general partner authorized a common unit repurchase program, under which we may repurchase up to $45 million of our outstanding common units through March 31, 2016. We may repurchase common units from time to time in the open market or in other privately negotiated transactions. The common unit repurchase program authorization does not obligate us to repurchase any dollar amount or number of our common units. The following table summarizes the repurchase of common units during the three months ended December 31, 2015.

				Total Number of
				Common Units	Approximate Dollar Value
	Total Number of	Average Price		Purchased as Part	of Common Units
	Common Units	Paid Per		of Publicly Announced	that May Yet Be Purchased
Period	Purchased	Common Unit		Program	Under the Program

October 1–31, 2015	—	$	—	—	$	41,349,748
November 1–30, 2015	78,321	17.93		66,333	40,175,794
December 1–31, 2015	174,182	16.67		174,182	37,272,180
Total	252,503	$	17.09	240,515	$	37,272,180

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

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

On February 4, 2016, H. Michael Krimbill was appointed to serve as the Interim Chief Financial Officer of NGL Energy Holdings LLC (the “General Partner”), our general partner, until a replacement for Atanas Atanasov, who resigned on January 27, 2016, is appointed.

Mr. Krimbill, 62, has served as our Chief Executive Officer since October 2010 and as a member of the board of directors of our general partner since its formation in September 2010. He will continue serving in this role while serving as Interim Chief Financial Officer.

102

Table of Contents

Item 6. Exhibits

Exhibit Number		Exhibit

4.1	*	Amendment No. 9 to Note Purchase Agreement, dated as of December 23, 2015, among the Partnership and the purchasers named therein
10.1	*	Facility Increase Agreement, dated October 7, 2015, among NGL Energy Operating LLC, Deutsche Bank Trust Company Americas and the other financial institutions party thereto
10.2	*	Amendment No. 11 to Credit Agreement, dated as of December 23, 2015 and effective as of December 23, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto
12.1	*	Computation of ratios of earnings to fixed charges
31.1	*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	**	XBRL Instance Document
101.SCH	**	XBRL Schema Document
101.CAL	**	XBRL Calculation Linkbase Document
101.DEF	**	XBRL Definition Linkbase Document
101.LAB	**	XBRL Label Linkbase Document
101.PRE	**	XBRL Presentation Linkbase Document

	*		Exhibits filed with this report.

	**		The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets at December 31, 2015 and March 31, 2015, (ii) Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2015 and 2014, (iii) Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and nine months ended December 31, 2015 and 2014, (iv) Condensed Consolidated Statement of Changes in Equity for the nine months ended December 31, 2015, (v) Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2015 and 2014, and (vi) Notes to Condensed Consolidated Financial Statements.

103

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 9, 2016		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer

Date: February 9, 2016		By:	/s/ Lawrence J. Thuillier
			Lawrence J. Thuillier
			Chief Accounting Officer

104

Table of Contents

INDEX TO EXHIBITS

Exhibit Number		Exhibit

4.1	*	Amendment No. 9 to Note Purchase Agreement, dated as of December 23, 2015, among the Partnership and the purchasers named therein
10.1	*	Facility Increase Agreement, dated October 7, 2015, among NGL Energy Operating LLC, Deutsche Bank Trust Company Americas and the other financial institutions party thereto
10.2	*	Amendment No. 11 to Credit Agreement, dated as of December 23, 2015 and effective as of December 23, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto
12.1	*	Computation of ratios of earnings to fixed charges
31.1	*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	**	XBRL Instance Document
101.SCH	**	XBRL Schema Document
101.CAL	**	XBRL Calculation Linkbase Document
101.DEF	**	XBRL Definition Linkbase Document
101.LAB	**	XBRL Label Linkbase Document
101.PRE	**	XBRL Presentation Linkbase Document

	*		Exhibits filed with this report.

	**		The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets at December 31, 2015 and March 31, 2015, (ii) Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2015 and 2014, (iii) Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and nine months ended December 31, 2015 and 2014, (iv) Condensed Consolidated Statement of Changes in Equity for the nine months ended December 31, 2015, (v) Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2015 and 2014, and (vi) Notes to Condensed Consolidated Financial Statements.

105

TABLE OF CONTENTS

Part I Item 1. Financial Statements (unaudited)Note 1 Organization and Operations Note 2 Significant Accounting Policies Note 3 Income (loss) Per Common Unit Note 4 Grand Mesa Pipeline Note 5 Acquisitions Note 6 Property, Plant and Equipment Note 7 Goodwill Note 8 Intangible Assets Note 9 Long-term Debt Note 10 Income Taxes Note 11 Commitments and Contingencies Note 12 Equity Note 13 Fair Value Of Financial Instruments Note 14 Segments Note 15 Goodwill Impairment Note 16 Transactions with Affiliates Note 17 Subsequent Events Note 18 Condensed Consolidating Guarantor and Non-guarantor Financial Information Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 3. Defaults Upon Senior Securities Item 4. Mine Safety Disclosures Item 5. Other Information Item 6. Exhibits

NGL 10-Q Quarter ended Dec. 31, 2015