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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 2017
OR
¨      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission File Number: 001-35172

NGL Energy Partners LP
(Exact Name of Registrant as Specified in Its Charter)
Delaware
 
27-3427920
(State or Other Jurisdiction of Incorporation or Organization)
 
(I.R.S. Employer Identification No.)
6120 South Yale Avenue, Suite 805
Tulsa, Oklahoma
 
74136
(Address of Principal Executive Offices)
 
(Zip Code)
(918) 481-1119
(Registrant’s Telephone Number, Including Area Code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer  x
 
Accelerated filer  ¨
Non-accelerated filer o (Do not check if a smaller reporting company)
 
Smaller reporting company ¨
Emerging growth company o
 
 

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

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

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




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TABLE OF CONTENTS

 
 
 
 
 
 
 
 
 
 
 
 


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Forward-Looking Statements

This Quarterly Report on Form 10-Q (“Quarterly Report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Certain words in this Quarterly Report such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “plan,” “project,” “will” and similar expressions and statements regarding our plans and objectives for future operations, identify forward-looking statements. Although we and our general partner believe such forward-looking statements are reasonable, neither we nor our general partner can assure they will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those expected. Among the key risk factors that may affect our consolidated financial position and results of operations are:

the prices of crude oil, natural gas liquids, gasoline, diesel, ethanol, and biodiesel;
energy prices generally;
the general level of crude oil, natural gas, and natural gas liquids production;
the general level of demand, and the availability of supply, for crude oil, natural gas liquids, gasoline, diesel, ethanol, and biodiesel;
the level of crude oil and natural gas drilling and production in areas where we have water treatment and disposal facilities;
the prices of propane and distillates relative to the prices of alternative and competing fuels;
the price of gasoline relative to the price of corn, which affects the price of ethanol;
the ability to obtain adequate supplies of products if an interruption in supply or transportation occurs and the availability of capacity to transport products to market areas;
actions taken by foreign oil and gas producing nations;
the political and economic stability of foreign oil and gas producing nations;
the effect of weather conditions on supply and demand for crude oil, natural gas liquids, gasoline, diesel, ethanol, and biodiesel;
the effect of natural disasters, lightning strikes, or other significant weather events;
the availability of local, intrastate, and interstate transportation infrastructure with respect to our truck, railcar, and barge transportation services;
the availability, price, and marketing of competing fuels;
the effect of energy conservation efforts on product demand;
energy efficiencies and technological trends;
governmental regulation and taxation;
the effect of legislative and regulatory actions on hydraulic fracturing, wastewater disposal, and the treatment of flowback and produced water;
hazards or operating risks related to transporting and distributing petroleum products that may not be fully covered by insurance;
the maturity of the crude oil, natural gas liquids, and refined products industries and competition from other marketers;
loss of key personnel;
the ability to renew contracts with key customers;
the ability to maintain or increase the margins we realize for our terminal, barging, trucking, wastewater disposal, recycling, and discharge services;
the ability to renew leases for our leased equipment and storage facilities;
the nonpayment or nonperformance by our counterparties;

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the availability and cost of capital and our ability to access certain capital sources;
a deterioration of the credit and capital markets;
the ability to successfully identify and complete accretive acquisitions, and integrate acquired assets and businesses;
changes in the volume of hydrocarbons recovered during the wastewater treatment process;
changes in the financial condition and results of operations of entities in which we own noncontrolling equity interests;
changes in applicable laws and regulations, including tax, environmental, transportation, and employment regulations, or new interpretations by regulatory agencies concerning such laws and regulations and the effect of such laws and regulations (now existing or in the future) on our business operations;
the costs and effects of legal and administrative proceedings;
any reduction or the elimination of the federal Renewable Fuel Standard; and
changes in the jurisdictional characteristics of, or the applicable regulatory policies with respect to, our pipeline assets.

You should not put undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date of this Quarterly Report. Except as may be required by state and federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events, or otherwise. When considering forward-looking statements, please review the risks discussed under Part I, Item 1A–“Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended March 31, 2017 and under Part II, Item 1A–“Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2017.


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PART I - FINANCIAL INFORMATION

Item 1.    Financial Statements

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Unaudited Condensed Consolidated Balance Sheets
(in Thousands, except unit amounts)
 
December 31, 2017
 
March 31, 2017
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
28,469

 
$
12,264

Accounts receivable-trade, net of allowance for doubtful accounts of $5,561 and $5,234, respectively
1,063,907

 
800,607

Accounts receivable-affiliates
3,517

 
6,711

Inventories
645,100

 
561,432

Prepaid expenses and other current assets
97,395

 
103,193

Assets held for sale
131,591

 

Total current assets
1,969,979

 
1,484,207

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $420,174 and $375,594, respectively
1,708,683

 
1,790,273

GOODWILL
1,313,317

 
1,451,716

INTANGIBLE ASSETS, net of accumulated amortization of $455,532 and $414,605, respectively
1,064,955

 
1,163,956

INVESTMENTS IN UNCONSOLIDATED ENTITIES
16,369

 
187,423

LOAN RECEIVABLE-AFFILIATE
318

 
3,200

OTHER NONCURRENT ASSETS
242,765

 
239,604

Total assets
$
6,316,386

 
$
6,320,379

LIABILITIES AND EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable-trade
$
866,768

 
$
658,021

Accounts payable-affiliates
474

 
7,918

Accrued expenses and other payables
230,752

 
207,125

Advance payments received from customers
46,850

 
35,944

Current maturities of long-term debt
3,260

 
29,590

Liabilities held for sale
16,574

 

Total current liabilities
1,164,678

 
938,598

LONG-TERM DEBT, net of debt issuance costs of $22,883 and $33,458, respectively, and current maturities
2,921,966

 
2,963,483

OTHER NONCURRENT LIABILITIES
168,281

 
184,534

COMMITMENTS AND CONTINGENCIES (NOTE 9)


 


 
 
 
 
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS, 19,942,169 and 19,942,169 preferred units issued and outstanding, respectively
76,056

 
63,890

REDEEMABLE NONCONTROLLING INTEREST
4,011

 
3,072

 
 
 
 
EQUITY:
 
 
 
General partner, representing a 0.1% interest, 121,205 and 120,300 notional units, respectively
(50,869
)
 
(50,529
)
Limited partners, representing a 99.9% interest, 121,083,664 and 120,179,407 common units issued and outstanding, respectively
1,823,740

 
2,192,413

Class B preferred limited partners, 8,400,000 and 0 preferred units issued and outstanding, respectively
202,731

 

Accumulated other comprehensive loss
(1,478
)
 
(1,828
)
Noncontrolling interests
7,270

 
26,746

Total equity
1,981,394

 
2,166,802

Total liabilities and equity
$
6,316,386

 
$
6,320,379


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

3



NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Unaudited Condensed Consolidated Statements of Operations
(in Thousands, except unit and per unit amounts)
 
 
Three Months Ended December 31,
 
Nine Months Ended December 31,
 
 
2017
 
2016
 
2017
 
2016
REVENUES:
 
 
 
 
 
 
 
 
Crude Oil Logistics
 
$
585,007

 
$
385,906

 
$
1,526,944

 
$
1,161,742

Water Solutions
 
64,024

 
40,359

 
162,023

 
115,845

Liquids
 
709,044

 
470,275

 
1,379,981

 
909,584

Retail Propane
 
160,025

 
128,654

 
291,797

 
240,131

Refined Products and Renewables
 
2,944,874

 
2,381,283

 
8,806,717

 
6,746,168

Other
 
289

 
164

 
696

 
679

Total Revenues
 
4,463,263

 
3,406,641

 
12,168,158

 
9,174,149

COST OF SALES:
 
 
 
 
 
 
 
 
Crude Oil Logistics
 
552,871

 
361,839

 
1,423,511

 
1,107,587

Water Solutions
 
10,192

 
477

 
13,019

 
3,871

Liquids
 
670,701

 
430,946

 
1,319,344

 
831,221

Retail Propane
 
87,487

 
60,508

 
148,443

 
106,019

Refined Products and Renewables
 
2,951,440

 
2,374,175

 
8,781,009

 
6,674,194

Other
 
117

 
77

 
311

 
300

Total Cost of Sales
 
4,272,808

 
3,228,022

 
11,685,637

 
8,723,192

OPERATING COSTS AND EXPENSES:
 
 
 
 
 
 
 
 
Operating
 
84,846

 
76,981

 
237,285

 
225,408

General and administrative
 
29,218

 
18,280

 
77,689

 
88,077

Depreciation and amortization
 
63,340

 
60,767

 
192,427

 
160,276

(Gain) loss on disposal or impairment of assets, net
 
(111,480
)
 
34

 
(11,242
)
 
(203,433
)
Revaluation of liabilities
 

 

 
5,600

 

Operating Income (Loss)
 
124,531

 
22,557

 
(19,238
)
 
180,629

OTHER INCOME (EXPENSE):
 
 
 
 
 
 

 
 

Equity in earnings of unconsolidated entities
 
3,426

 
1,279

 
7,270

 
1,726

Revaluation of investments
 

 

 

 
(14,365
)
Interest expense
 
(51,790
)
 
(41,436
)
 
(151,249
)
 
(105,316
)
(Loss) gain on early extinguishment of liabilities, net
 
(21,141
)
 

 
(22,479
)
 
30,890

Other income, net
 
2,107

 
20,007

 
6,113

 
25,860

Income (Loss) Before Income Taxes
 
57,133

 
2,407

 
(179,583
)
 
119,424

INCOME TAX EXPENSE
 
(364
)
 
(1,114
)
 
(934
)
 
(2,036
)
Net Income (Loss)
 
56,769

 
1,293

 
(180,517
)
 
117,388

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
(89
)
 
(317
)
 
(221
)
 
(6,091
)
LESS: NET (INCOME) LOSS ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS
 
(424
)
 

 
261

 

NET INCOME (LOSS) ATTRIBUTABLE TO NGL ENERGY PARTNERS LP
 
56,256

 
976

 
(180,477
)
 
111,297

LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS
 
(16,219
)
 
(8,906
)
 
(42,001
)
 
(20,958
)
LESS: NET (INCOME) LOSS ALLOCATED TO GENERAL PARTNER
 
(73
)
 
(22
)
 
121

 
(180
)
LESS: REPURCHASE OF WARRANTS
 

 

 
(349
)
 

NET INCOME (LOSS) ALLOCATED TO COMMON UNITHOLDERS
 
$
39,964

 
$
(7,952
)
 
$
(222,706
)
 
$
90,159

BASIC INCOME (LOSS) PER COMMON UNIT
 
$
0.33

 
$
(0.07
)
 
$
(1.84
)
 
$
0.85

DILUTED INCOME (LOSS) PER COMMON UNIT
 
$
0.32

 
$
(0.07
)
 
$
(1.84
)
 
$
0.82

BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING
 
120,844,008

 
107,966,901

 
120,899,502

 
106,114,668

DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING
 
124,161,966

 
107,966,901

 
120,899,502

 
109,554,928


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

4



NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)
(in Thousands)
 
 
Three Months Ended December 31,
 
Nine Months Ended December 31,
 
 
2017
 
2016
 
2017
 
2016
Net income (loss)
 
$
56,769

 
$
1,293

 
$
(180,517
)
 
$
117,388

Other comprehensive income
 
784

 
545

 
350

 
60

Comprehensive income (loss)
 
$
57,553

 
$
1,838

 
$
(180,167
)
 
$
117,448


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


5



NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Unaudited Condensed Consolidated Statement of Changes in Equity
Nine Months Ended December 31, 2017
(in Thousands, except unit amounts)
 
 
 
 
Limited Partners
 
 
 
 
 
 
 
 
 
 
Class B Preferred
 
Common
 
Accumulated
Other
 
 
 
 
 
 
General
Partner
 
Units
 
Amount
 

Units
 
Amount
 
Comprehensive
Loss
 
Noncontrolling
Interests
 
Total
Equity
BALANCES AT MARCH 31, 2017
 
$
(50,529
)
 

 
$

 
120,179,407

 
$
2,192,413

 
$
(1,828
)
 
$
26,746

 
$
2,166,802

Distributions to general and common unit partners and preferred unitholders (Note 10)
 
(242
)
 

 

 

 
(171,072
)
 

 

 
(171,314
)
Distributions to noncontrolling interest owners
 

 

 

 

 

 

 
(3,082
)
 
(3,082
)
Contributions
 

 

 

 

 

 

 
23

 
23

Purchase of noncontrolling interest (Note 4)
 

 

 

 

 
(6,245
)
 

 
(16,638
)
 
(22,883
)
Redemption valuation adjustment (Note 2)
 

 

 

 

 
(1,201
)
 

 

 
(1,201
)
Repurchase of warrants (Note 10)
 

 

 

 

 
(10,549
)
 

 

 
(10,549
)
Equity issued pursuant to incentive compensation plan (Note 10)
 
23

 

 

 
1,855,102

 
28,611

 

 

 
28,634

Common unit repurchases and cancellations (Note 10)
 

 

 

 
(1,558,498
)
 
(15,608
)
 

 

 
(15,608
)
Warrants exercised (Note 10)
 

 

 

 
607,653

 
6

 

 

 
6

Accretion of beneficial conversion feature of Class A convertible preferred units (Note 10)
 

 

 

 

 
(12,259
)
 

 

 
(12,259
)
Issuance of Class B preferred units (Note 10)
 

 
8,400,000

 
202,731

 

 

 

 

 
202,731

Net (loss) income
 
(121
)
 

 

 

 
(180,356
)
 

 
221

 
(180,256
)
Other comprehensive income
 

 

 

 

 

 
350

 

 
350

BALANCES AT DECEMBER 31, 2017
 
$
(50,869
)
 
8,400,000

 
$
202,731

 
121,083,664

 
$
1,823,740

 
$
(1,478
)
 
$
7,270

 
$
1,981,394


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


6



NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Unaudited Condensed Consolidated Statements of Cash Flows
(in Thousands)
 
 
Nine Months Ended December 31,
 
 
2017
 
2016
OPERATING ACTIVITIES:
 
 
 
 
Net (loss) income
 
$
(180,517
)
 
$
117,388

Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
 
 
 
 
Depreciation and amortization, including amortization of debt issuance costs
 
205,192

 
173,566

Loss (gain) on early extinguishment or revaluation of liabilities, net
 
28,079

 
(30,890
)
Gain on termination of a storage sublease agreement
 

 
(16,205
)
Non-cash equity-based compensation expense
 
27,114

 
39,859

Gain on disposal or impairment of assets, net
 
(11,242
)
 
(203,433
)
Provision for doubtful accounts
 
1,910

 
471

Net adjustments to fair value of commodity derivatives
 
99,814

 
102,638

Equity in earnings of unconsolidated entities
 
(7,270
)
 
(1,726
)
Distributions of earnings from unconsolidated entities
 
4,891

 
2,094

Revaluation of investments
 

 
14,365

Other
 
854

 
(3,269
)
Changes in operating assets and liabilities, exclusive of acquisitions:
 
 
 
 
Accounts receivable-trade and affiliates
 
(278,547
)
 
(245,065
)
Inventories
 
(90,037
)
 
(244,941
)
Other current and noncurrent assets
 
(11,534
)
 
(65,331
)
Accounts payable-trade and affiliates
 
200,363

 
245,506

Other current and noncurrent liabilities
 
14,991

 
(599
)
Net cash provided by (used in) operating activities
 
4,061

 
(115,572
)
INVESTING ACTIVITIES:
 
 
 
 
Capital expenditures
 
(99,384
)
 
(264,580
)
Acquisitions, net of cash acquired
 
(49,481
)
 
(127,513
)
Cash flows from settlements of commodity derivatives
 
(85,823
)
 
(82,815
)
Proceeds from sales of assets
 
33,673

 
14,195

Proceeds from sale of interest in Glass Mountain
 
292,117

 

Proceeds from sale of TLP common units
 

 
112,370

Proceeds from sale of Grassland
 

 
22,000

Transaction with an unconsolidated entity (Note 13)
 
(6,424
)
 

Investments in unconsolidated entities
 
(21,461
)
 

Distributions of capital from unconsolidated entities
 
11,710

 
7,608

Repayments on loan for natural gas liquids facility
 
7,425

 
6,585

Loan to affiliate
 
(1,460
)
 
(2,700
)
Repayments on loan to affiliate
 
4,160

 
655

Payment to terminate development agreement
 

 
(16,875
)
Other (Note 14)
 
20,000

 

Net cash provided by (used in) investing activities
 
105,052

 
(331,070
)
FINANCING ACTIVITIES:
 
 
 
 
Proceeds from borrowings under Revolving Credit Facility
 
1,674,500

 
1,176,000

Payments on Revolving Credit Facility
 
(1,349,500
)
 
(1,510,500
)
Issuance of senior unsecured notes
 

 
700,000

Repayment and repurchase of senior secured and senior unsecured notes
 
(415,568
)
 
(15,129
)
Payments on other long-term debt
 
(4,361
)
 
(6,549
)
Debt issuance costs
 
(2,497
)
 
(12,608
)
Contributions from general partner
 

 
59

Contributions from noncontrolling interest owners, net
 
23

 
639

Distributions to general and common unit partners and preferred unitholders
 
(166,589
)
 
(132,135
)
Distributions to noncontrolling interest owners
 
(3,082
)
 
(3,292
)
Proceeds from sale of preferred units, net of offering costs
 
202,731

 
234,989

Repurchase of warrants
 
(10,549
)
 

Common unit repurchases and cancellations
 
(15,608
)
 

Proceeds from sale of common units, net of offering costs
 

 
43,896

Payments for settlement and early extinguishment of liabilities
 
(2,408
)
 
(27,977
)
Net cash (used in) provided by financing activities
 
(92,908
)
 
447,393

Net increase in cash and cash equivalents
 
16,205

 
751

Cash and cash equivalents, beginning of period
 
12,264

 
28,176

Cash and cash equivalents, end of period
 
$
28,469

 
$
28,927

Supplemental cash flow information:
 
 
 
 
Cash interest paid
 
$
153,788

 
$
89,102

Income taxes paid (net of income tax refunds)
 
$
1,614

 
$
1,985

Supplemental non-cash investing and financing activities:
 
 
 
 
Distributions declared but not paid to Class B preferred unitholders
 
$
4,725

 
$

Accrued capital expenditures
 
$
7,444

 
$
2,754

Value of common units issued in business combinations
 
$

 
$
3,947

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

7

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements


Note 1 —Organization and Operations

NGL Energy Partners LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership . NGL Energy Holdings LLC serves as our general partner. At December 31, 2017 , our operations include:

Our Crude Oil Logistics segment purchases crude oil from producers and transports it to refineries or for resale at pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs, and provides terminaling, trucking, marine and pipeline transportation services through its owned assets.
Our Water Solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production and for the disposal of solids such as tank bottoms and drilling fluids and performs truck and frac tank washouts. In addition, our Water Solutions segment sells the recovered hydrocarbons that result from performing these services.
Our Liquids segment supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada using its leased underground storage and fleet of leased railcars, markets regionally through its 21 owned terminals throughout the United States, and provides terminaling and storage services at its salt dome storage facility in Utah.
Our Retail Propane segment sells propane, distillates, equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 30 states and the District of Columbia.
Our Refined Products and Renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations, purchases refined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedules them for delivery at various locations throughout the country.

Note 2 —Significant Accounting Policies

Basis of Presentation

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

Our unaudited condensed consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim consolidated financial information in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the unaudited condensed consolidated financial statements exclude certain information and notes required by GAAP for complete annual consolidated financial statements. However, we believe that the disclosures made are adequate to make the information presented not misleading. The unaudited condensed consolidated financial statements include all adjustments that we consider necessary for a fair presentation of our consolidated financial position and results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed in this Quarterly Report. The unaudited condensed consolidated balance sheet at March 31, 2017 was derived from our audited consolidated financial statements for the fiscal year ended March 31, 2017 included in our Annual Report on Form 10-K (“Annual Report”) filed with the SEC on May 26, 2017.

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


8

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Use of Estimates

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

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

Significant Accounting Policies

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

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability. We use the following fair value hierarchy, which prioritizes valuation technique inputs used to measure fair value into three broad levels:

Level 1: Quoted prices in active markets for identical assets and liabilities that we have the ability to access at the measurement date.
Level 2: Inputs (other than quoted prices included within Level 1) that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability, and (iv) inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity price swap and option contracts and forward commodity contracts. We determine the fair value of all of our derivative financial instruments utilizing pricing models for similar instruments. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.
Level 3: Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

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

Derivative Financial Instruments

We record all derivative financial instrument contracts at fair value in our unaudited condensed consolidated balance sheets except for certain contracts that qualify for the normal purchase and normal sale election . Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs.

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

9

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


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

We utilize various commodity derivative financial instrument contracts to attempt to reduce our exposure to price fluctuations. We do not enter into such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in market prices, newly originated transactions, and the timing of settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipated market movements. Inherent in the resulting contractual portfolio are certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that the market value of crude oil, natural gas liquids, or refined and renewables products will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions.

Revenue Recognition

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

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

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

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

Income Taxes

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

We have certain taxable corporate subsidiaries in Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales.

We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax

10

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in our unaudited condensed consolidated financial statements at December 31, 2017 or March 31, 2017 .

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

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

Inventories

We value our inventories at the lower of cost or market, with cost determined using either the weighted-average cost or the first in, first out (FIFO) methods, including the cost of transportation and storage. Market is determined based on estimated replacement cost using prices at the end of the reporting period. On April 1, 2017, we adopted the new inventory standard, Accounting Standards Update (“ASU”) No. 2015-11. Under this ASU, inventory is to be measured at the lower of cost or net realizable value, which is defined as the estimated selling price in the ordinary course of business, less reasonable predictable costs of completion, disposal, and transportation. In performing this analysis, we consider fixed-price forward commitments and the opportunity to transfer propane inventory from our wholesale Liquids business to our Retail Propane business to sell the inventory in retail markets.

Inventories consist of the following at the dates indicated:
 
 
December 31, 2017
 
March 31, 2017
 
 
(in thousands)
Crude oil
 
$
77,306

 
$
146,857

Natural gas liquids:
 
 
 
 
Propane
 
118,998

 
38,631

Butane
 
40,670

 
5,992

Other
 
11,778

 
6,035

Refined products:
 
 
 
 
Gasoline
 
214,717

 
193,051

Diesel
 
129,126

 
98,237

Renewables:
 
 
 
 
Ethanol
 
39,631

 
42,009

Biodiesel
 
8,124

 
21,410

Other
 
4,750

 
9,210

Total
 
$
645,100

 
$
561,432


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

Investments in Unconsolidated Entities

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

11

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


investments in unincorporated joint ventures are also accounted for using the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on our unaudited condensed consolidated balance sheets; instead, our ownership interests are reported within investments in unconsolidated entities on our unaudited condensed consolidated balance sheets. Under the equity method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions paid, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the historical net book value of the net assets of the investee. We use the cumulative earnings approach to classify distributions received from unconsolidated entities as either operating activities or investing activities in our unaudited condensed consolidated statements of cash flows.

Our investments in unconsolidated entities consist of the following at the dates indicated:
Entity
 
Segment
 
Ownership
Interest (1)
 
Date Acquired
or Formed
 
December 31, 2017
 
March 31, 2017
 
 
 
 
 
 
 
 
(in thousands)
Glass Mountain Pipeline, LLC (2)
 
Crude Oil Logistics
 
—%
 
December 2013
 
$

 
$
172,098

E Energy Adams, LLC
 
Refined Products and Renewables
 
19%
 
December 2013
 
14,369

 
12,952

Water treatment and disposal facility (3)
 
Water Solutions
 
50%
 
August 2015
 
2,000

 
2,147

Victory Propane, LLC (4)
 
Retail Propane
 
50%
 
April 2015
 

 
226

Total
 
 
 
 
 
 
 
$
16,369

 
$
187,423

 
(1)
Ownership interest percentages are at December 31, 2017 .
(2)
On December 22, 2017, we sold our previously held 50% interest in Glass Mountain Pipeline, LLC for net proceeds of $292.1 million and recorded a gain on disposal of $108.6 million during the three months ended December 31, 2017 within (gain) loss on disposal or impairment of assets, net in our unaudited condensed consolidated statement of operations.
(3)
This is an investment in an unincorporated joint venture.
(4)
As our investment is $0 at December 31, 2017 , our proportionate share of Victory Propane, LLC’s (“Victory Propane”) losses have been recorded against the loan receivable we have with Victory Propane. See Note 13 for a further discussion of the loan receivable and a description of other transactions between us and Victory Propane.

Variable Interest Entity

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


12

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Other Noncurrent Assets

Other noncurrent assets consist of the following at the dates indicated:
 
 
December 31, 2017
 
March 31, 2017
 
 
(in thousands)
Loan receivable (1)
 
$
32,396

 
$
40,684

Line fill (2)
 
36,446

 
30,628

Tank bottoms (3)
 
42,044

 
42,044

Minimum shipping fees - pipeline commitments (4)
 
82,301

 
67,996

Other
 
49,578

 
58,252

Total
 
$
242,765

 
$
239,604

 
(1)
Represents a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party .
(2)
Represents minimum volumes of product we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At December 31, 2017 , line fill consisted of 377,320 barrels of crude oil and 262,000 barrels of propane (requirement is due to a new contract). At March 31, 2017 , line fill consisted of 427,193 barrels of crude oil. Line fill held in pipelines we own is included within property, plant and equipment (see Note 5 ).
(3)
Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms when the storage tanks are removed from service. At December 31, 2017 and March 31, 2017 , tank bottoms held in third party terminals consisted of 366,212 barrels and 366,212 barrels of refined products, respectively. Tank bottoms held in terminals we own are included within property, plant and equipment (see Note 5 ).
(4)
Represents the minimum shipping fees paid in excess of volumes shipped for two contracts. This amount can be recovered when volumes shipped exceed the minimum monthly volume commitment (see Note 9 ). Under these contracts, we currently have 2.3 years and 2.8 years , respectively, in which to ship the excess volumes.

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following at the dates indicated:
 
 
December 31, 2017
 
March 31, 2017
 
 
(in thousands)
Accrued compensation and benefits
 
$
16,237

 
$
22,227

Excise and other tax liabilities
 
48,803

 
64,051

Derivative liabilities
 
34,713

 
27,622

Accrued interest
 
33,389

 
44,418

Product exchange liabilities
 
24,312

 
1,693

Deferred gain on sale of general partner interest in TLP
 
30,113

 
30,113

Other
 
43,185

 
17,001

Total
 
$
230,752

 
$
207,125


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

Deferred Gain on Sale of General Partner Interest in TLP

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

13

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


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

Noncontrolling Interests

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

Business Combination Measurement Period

We record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination. As discussed in Note 4 , certain of our acquisitions are still within this measurement period, and as a result, the acquisition date fair values we have recorded for the assets acquired and liabilities assumed are subject to change.

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

Reclassifications

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

Recent Accounting Pronouncements

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

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

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

14

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


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

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The ASU will replace most existing revenue recognition guidance in GAAP. The core principle of this ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU is effective for the Partnership beginning April 1, 2018, and allows for both full retrospective and modified retrospective methods of adoption.

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

Note 3— Income (Loss) Per Common Unit

The following table presents our calculation of basic and diluted weighted average units outstanding for the periods indicated:
 
Three Months Ended December 31,
 
Nine Months Ended December 31,
 
2017
 
2016
 
2017
 
2016
Weighted average units outstanding during the period:
 
 
 
 
 
 
 
Common units - Basic
120,844,008

 
107,966,901

 
120,899,502

 
106,114,668

Effect of Dilutive Securities:
 
 
 
 
 
 
 
Performance awards

 

 

 
111,826

Warrants
2,914,383

 

 

 
3,328,434

Service awards
403,575

 

 

 

Common units - Diluted
124,161,966

 
107,966,901

 
120,899,502

 
109,554,928


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

15

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Our income (loss) per common unit is as follows for the periods indicated:
 
Three Months Ended December 31,
 
Nine Months Ended December 31,
 
2017
 
2016
 
2017
 
2016
 
(in thousands, except unit and per unit amounts)
Net income (loss)
$
56,769

 
$
1,293

 
$
(180,517
)
 
$
117,388

Less: Net income attributable to noncontrolling interests
(89
)
 
(317
)
 
(221
)
 
(6,091
)
Less: Net (income) loss attributable to redeemable noncontrolling interests
(424
)
 

 
261

 

Net income (loss) attributable to NGL Energy Partners LP
56,256

 
976

 
(180,477
)
 
111,297

Less: Distributions to preferred unitholders
(16,219
)
 
(8,906
)
 
(42,001
)
 
(20,958
)
Less: Net (income) loss allocated to general partner (1)
(73
)
 
(22
)
 
121

 
(180
)
Less: Repurchase of warrants (2)

 

 
(349
)
 

Net income (loss) allocated to common unitholders
$
39,964

 
$
(7,952
)
 
$
(222,706
)
 
$
90,159

Basic income (loss) per common unit
$
0.33

 
$
(0.07
)
 
$
(1.84
)
 
$
0.85

Diluted income (loss) per common unit
$
0.32

 
$
(0.07
)
 
$
(1.84
)
 
$
0.82

Basic weighted average common units outstanding
120,844,008

 
107,966,901

 
120,899,502

 
106,114,668

Diluted weighted average common units outstanding
124,161,966

 
107,966,901

 
120,899,502

 
109,554,928

 
(1)
Net (income) loss allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights.
(2)
This amount represents the excess of the repurchase price over the fair value of the warrants, as discussed further in Note 10 .

Note 4 —Acquisitions

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

Acquisition of Remaining Interest in NGL Solids Solutions, LLC

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

The remaining 50% interest in NGL Solids Solutions, LLC; and
Two parcels of land to develop saltwater disposal wells.

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

Retail Propane Businesses

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


16

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed for these retail propane businesses, and as a result, the estimates of fair value at December 31, 2017 are subject to change. The following table summarizes the preliminary estimates of the fair values of the assets acquired and liabilities assumed (in thousands):
Current assets
$
2,042

Property, plant and equipment
10,686

Goodwill
3,010

Intangible assets
16,625

Current liabilities
(1,586
)
Other noncurrent liabilities
(291
)
Fair value of net assets acquired
$
30,486


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

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

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

Water Solutions Facilities

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

Retail Propane Businesses

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

Natural Gas Liquids Facilities

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


17

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Note 5 —Property, Plant and Equipment
  
Our property, plant and equipment consists of the following at the dates indicated:
Description
 
Estimated
Useful Lives
 
December 31, 2017
 
March 31, 2017
 
 
 
 
(in thousands)
Natural gas liquids terminal and storage assets
 
2–30 years
 
$
238,092

 
$
207,825

Pipeline and related facilities
 
30–40 years
 
255,930

 
248,582

Refined products terminal assets and equipment
 
15–25 years
 
7,062

 
6,736

Retail propane equipment
 
2–30 years
 
195,414

 
239,417

Vehicles and railcars
 
3–25 years
 
179,691

 
198,480

Water treatment facilities and equipment
 
3–30 years
 
585,569

 
557,100

Crude oil tanks and related equipment
 
2–30 years
 
218,056

 
203,003

Barges and towboats
 
5–30 years
 
91,884

 
91,037

Information technology equipment
 
3–7 years
 
43,495

 
43,880

Buildings and leasehold improvements
 
3–40 years
 
167,446

 
161,957

Land
 
 
 
56,593

 
56,545

Tank bottoms and line fill (1)
 
 
 
20,094

 
24,462

Other
 
3–20 years
 
14,802

 
39,132

Construction in progress
 
 
 
54,729

 
87,711

 
 
 
 
2,128,857

 
2,165,867

Accumulated depreciation
 
 
 
(420,174
)
 
(375,594
)
Net property, plant and equipment
 
 
 
$
1,708,683

 
$
1,790,273

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

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

The following table summarizes depreciation expense and capitalized interest expense for the periods indicated:
 
 
Three Months Ended December 31,
 
Nine Months Ended December 31,
 
 
2017
 
2016
 
2017
 
2016
 
 
(in thousands)
Depreciation expense
 
$
32,629

 
$
32,039

 
$
98,761

 
$
88,396

Capitalized interest expense
 
$
66

 
$
1,429

 
$
66

 
$
6,233


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


18

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Note 6 —Goodwill

The following table summarizes changes in goodwill by segment during the nine months ended December 31, 2017 :
 
 
Crude Oil
Logistics
 
Water
Solutions
 
Liquids
 
Retail
Propane
 
Refined
Products and
Renewables
 
Total
 
 
(in thousands)
Balances at March 31, 2017
 
$
579,846

 
$
424,270

 
$
266,046

 
$
130,427

 
$
51,127

 
$
1,451,716

Revisions to acquisition accounting (Note 4)
 

 
195

 

 
232

 

 
427

Acquisitions (Note 4)
 

 

 

 
3,010

 

 
3,010

Impairment
 

 

 
(116,877
)
 

 

 
(116,877
)
Assets held for sale (Note 14)
 

 

 

 
(24,959
)
 

 
(24,959
)
Balances at December 31, 2017
 
$
579,846

 
$
424,465

 
$
149,169

 
$
108,710

 
$
51,127

 
$
1,313,317


Goodwill Impairment

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

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

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


19

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Note 7 —Intangible Assets

Our intangible assets consist of the following at the dates indicated:
 
 
 
 
December 31, 2017
 
March 31, 2017
Description
 
Amortizable Lives
 
Gross Carrying
Amount
 
Accumulated
Amortization
 
Net
 
Gross Carrying
Amount
 
Accumulated
Amortization
 
Net
 
 
 
 
(in thousands)
Amortizable:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Customer relationships
 
3–20 years
 
$
882,256

 
$
(352,364
)
 
$
529,892

 
$
906,782

 
$
(316,242
)
 
$
590,540

Customer commitments
 
10 years
 
310,000

 
(36,167
)
 
273,833

 
310,000

 
(12,917
)
 
297,083

Pipeline capacity rights
 
30 years
 
161,785

 
(15,697
)
 
146,088

 
161,785

 
(11,652
)
 
150,133

Rights-of-way and easements
 
1–40 years
 
63,485

 
(2,670
)
 
60,815

 
63,402

 
(2,154
)
 
61,248

Executory contracts and other agreements
 
3–30 years
 
23,097

 
(16,626
)
 
6,471

 
29,036

 
(20,457
)
 
8,579

Non-compete agreements
 
2–32 years
 
17,988

 
(6,767
)
 
11,221

 
32,984

 
(17,762
)
 
15,222

Trade names
 
1–10 years
 
4,076

 
(1,822
)
 
2,254

 
15,439

 
(13,396
)
 
2,043

Debt issuance costs (1)
 
5 years
 
40,790

 
(23,419
)
 
17,371

 
38,983

 
(20,025
)
 
18,958

Total amortizable
 
 
 
1,503,477

 
(455,532
)
 
1,047,945

 
1,558,411

 
(414,605
)
 
1,143,806

Non-amortizable:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trade names
 
 
 
17,010

 

 
17,010

 
20,150

 

 
20,150

Total non-amortizable
 
 
 
17,010

 

 
17,010

 
20,150

 

 
20,150

Total
 
 
 
$
1,520,487

 
$
(455,532
)
 
$
1,064,955

 
$
1,578,561

 
$
(414,605
)
 
$
1,163,956

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

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

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

Write off of Intangible Asset

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

Amortization expense is as follows for the periods indicated:
 
 
Three Months Ended December 31,
 
Nine Months Ended December 31,
Recorded In
 
2017
 
2016
 
2017
 
2016
 
 
(in thousands)
Depreciation and amortization
 
$
30,711

 
$
28,728

 
$
93,666

 
$
71,880

Cost of sales
 
1,505

 
1,753

 
4,596

 
5,098

Interest expense
 
1,154

 
1,721

 
3,394

 
5,177

Total
 
$
33,370

 
$
32,202

 
$
101,656

 
$
82,155



20

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Expected amortization of our intangible assets is as follows (in thousands):
Fiscal Year Ending March 31,
 
2018 (three months)
$
32,936

2019
128,009

2020
124,632

2021
111,519

2022
96,432

Thereafter
554,417

Total
$
1,047,945


Note 8 —Long-Term Debt

Our long-term debt consists of the following at the dates indicated:
 
 
December 31, 2017
 
March 31, 2017
 
 
Face
Amount
 
Unamortized
Debt Issuance
Costs (1)
 
Book
Value
 
Face
Amount
 
Unamortized
Debt Issuance
Costs (1)
 
Book
Value
 
 
(in thousands)
Revolving credit facility:
 
 
 
 
 
 
 
 
 
 
 
 
Expansion capital borrowings
 
$
125,000

 
$

 
$
125,000

 
$

 
$

 
$

Working capital borrowings
 
1,014,500

 

 
1,014,500

 
814,500

 

 
814,500

Senior secured notes
 

 

 

 
250,000

 
(4,559
)
 
245,441

Senior unsecured notes:
 
 
 
 
 
 
 
 
 
 
 
 
5.125% Notes due 2019
 
360,781

 
(2,015
)
 
358,766

 
379,458

 
(3,191
)
 
376,267

6.875% Notes due 2021
 
367,048

 
(4,817
)
 
362,231

 
367,048

 
(5,812
)
 
361,236

7.500% Notes due 2023
 
656,589

 
(9,515
)
 
647,074

 
700,000

 
(11,329
)
 
688,671

6.125% Notes due 2025
 
412,507

 
(6,536
)
 
405,971

 
500,000

 
(8,567
)
 
491,433

Other long-term debt
 
11,684

 

 
11,684

 
15,525

 

 
15,525

 
 
2,948,109

 
(22,883
)
 
2,925,226

 
3,026,531

 
(33,458
)
 
2,993,073

Less: Current maturities
 
3,260

 

 
3,260

 
29,590

 

 
29,590

Long-term debt
 
$
2,944,849

 
$
(22,883
)
 
$
2,921,966

 
$
2,996,941

 
$
(33,458
)
 
$
2,963,483

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

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

Expected amortization of debt issuance costs is as follows (in thousands):
Fiscal Year Ending March 31,
 
 
2018 (three months)
 
$
1,283

2019
 
5,124

2020
 
4,191

2021
 
3,810

2022
 
3,229

Thereafter
 
5,246

Total
 
$
22,883



21

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Credit Agreement

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

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

On June 2, 2017, we amended our Credit Agreement. The amendment, among other things, restricts us from increasing our distribution rate over the amount paid in the preceding quarter if our leverage ratio is greater than 4.25 to 1. In addition, the Credit Agreement contains covenants that require us to satisfy certain debt ratios, which are summarized in the table below.
 
 
 
 
Senior Secured
 
Interest
Period Beginning
 
Leverage Ratio (1)
 
Leverage Ratio (1)
 
Coverage Ratio (2)
December 31, 2017
 
5.50

 
2.50

 
2.25

March 31, 2018
 
4.75

 
3.25

 
2.75

March 31, 2019 and thereafter
 
4.50

 
3.25

 
2.75

 
(1)
Amount represents the maximum ratio for the period presented.
(2)
Amount represents the minimum ratio for the period presented.

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

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

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

Senior Secured Notes

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


22

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Repurchases

On December 29, 2017, we repurchased all of the remaining outstanding Senior Secured Notes. The following table summarizes repurchases of Senior Secured Notes for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
December 31,
 
December 31,
 
 
2017
 
2017
 
 
(in thousands)
Senior Secured Notes
 
 
 
 
Notes repurchased
 
$
175,500

 
$
230,500

Cash paid (excluding payments of accrued interest)
 
$
192,979

 
$
250,179

Loss on early extinguishment of debt (1)
 
$
(20,807
)
 
$
(23,971
)
 
(1)
Loss on the early extinguishment of debt for the Senior Secured Notes during the three months and nine months ended December 31, 2017 are net of debt issuance costs of $3.3 million and $4.3 million , respectively.

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

Senior Unsecured Notes

Registration Rights

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


23

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Repurchases

The following table summarizes repurchases of Senior Unsecured Notes for the periods indicated:
 
 
Three Months Ended
 
Nine Months Ended
 
 
December 31,
 
December 31,
 
 
2017
 
2017
 
 
(in thousands)
2019 Notes
 
 
 
 
Notes repurchased
 
$

 
$
18,677

Cash paid (excluding payments of accrued interest)
 
$

 
$
18,641

Loss on early extinguishment of debt (1)
 
$

 
$
(102
)
 
 
 
 
 
2023 Notes
 
 
 
 
Notes repurchased
 
$
16,954

 
$
43,411

Cash paid (excluding payments of accrued interest)
 
$
17,434

 
$
42,893

Loss on early extinguishment of debt (2)
 
$
(730
)
 
$
(135
)
 
 
 
 
 
2025 Notes
 
 
 
 
Notes repurchased
 
$
71,793

 
$
87,493

Cash paid (excluding payments of accrued interest)
 
$
70,248

 
$
84,356

Gain on early extinguishment of debt (3)
 
$
396

 
$
1,729

 
(1)
Loss on the early extinguishment of debt for the 2019 Notes during the nine months ended December 31, 2017 are net of debt issuance costs of $0.1 million .
(2)
Loss on the early extinguishment of debt for the 2023 Notes during the three months and nine months ended December 31, 2017 are net of debt issuance costs of $0.2 million and $0.7 million , respectively.
(3)
Gain on the early extinguishment of debt for the 2025 Notes during the three months and nine months ended December 31, 2017 are net of debt issuance costs of $1.1 million and $1.4 million , respectively.

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

Other Long-Term Debt

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


24

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at December 31, 2017 :
Fiscal Year Ending March 31,
 
Revolving
Credit
Facility
 
Senior Unsecured Notes
 
Other
Long-Term
Debt
 
Total
 
 
(in thousands)
2018 (three months)
 
$

 
$

 
$
604

 
$
604

2019
 

 

 
2,939

 
2,939

2020
 

 
360,781

 
2,318

 
363,099

2021
 

 

 
5,470

 
5,470

2022
 
1,139,500

 
367,048

 
286

 
1,506,834

Thereafter
 

 
1,069,096

 
67

 
1,069,163

Total
 
$
1,139,500

 
$
1,796,925

 
$
11,684

 
$
2,948,109


Note 9 —Commitments and Contingencies

Legal Contingencies

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

Environmental Matters

Our unaudited condensed consolidated balance sheet at December 31, 2017 includes a liability, measured on an undiscounted basis, of $2.3 million related to environmental matters, which is recorded within accrued expenses and other payables in our unaudited condensed consolidated balance sheet. Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there can be no assurance that we will not incur significant costs. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

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


25

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Asset Retirement Obligations

We have contractual and regulatory obligations at certain facilities for which we have to perform remediation, dismantlement, or removal activities when the assets are retired. Our liability for asset retirement obligations is discounted to present value. To calculate the liability, we make estimates and assumptions about the retirement cost and the timing of retirement. Changes in our assumptions and estimates may occur as a result of the passage of time and the occurrence of future events. The following table summarizes changes in our asset retirement obligation, which is reported within other noncurrent liabilities in our unaudited condensed consolidated balance sheets (in thousands):
Balance at March 31, 2017
$
8,181

Liabilities incurred
422

Liabilities assumed in acquisitions
21

Liabilities settled
(549
)
Accretion expense
655

Balance at December 31, 2017
$
8,730


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

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment. The following table summarizes future minimum lease payments under these agreements at December 31, 2017 (in thousands):
Fiscal Year Ending March 31,
 
2018 (three months)
$
34,721

2019
120,928

2020
107,342

2021
93,662

2022
66,036

Thereafter
94,023

Total
$
516,712


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

Pipeline Capacity Agreements

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


26

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


The following table summarizes future minimum throughput payments under these agreements at December 31, 2017 (in thousands):
Fiscal Year Ending March 31,
 
2018 (three months)
$
13,001

2019
52,042

2020
42,351

Total
$
107,394


Construction Commitments

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

Sales and Purchase Contracts

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

At December 31, 2017 , we had the following commodity purchase commitments (in thousands):
 
 
Crude Oil (1)
 
Natural Gas Liquids
 
 
Value
 
Volume
(in barrels)
 
Value
 
Volume
(in gallons)
Fixed-Price Commodity Purchase Commitments:
 
 
 
 
 
 
 
 
2018 (three months)
 
$
51,001

 
899

 
$
20,600

 
26,213

2019
 

 

 
1,341

 
2,268

Total
 
$
51,001

 
899

 
$
21,941

 
28,481

 
 
 
 
 
 
 
 
 
Index-Price Commodity Purchase Commitments:
 
 
 
 
 
 
 
 
2018 (three months)
 
$
427,214

 
7,386

 
$
310,124

 
319,467

2019
 
790,287

 
14,640

 
46,559

 
50,644

2020
 
511,636

 
10,395

 

 

2021
 
438,851

 
9,314

 

 

2022
 
357,603

 
7,729

 

 

Thereafter
 
447,158

 
9,592

 

 

Total
 
$
2,972,749

 
59,056

 
$
356,683

 
370,111

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

27

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


At December 31, 2017 , we had the following commodity sale commitments (in thousands):
 
 
Crude Oil
 
Natural Gas Liquids
 
 
Value
 
Volume
(in barrels)
 
Value
 
Volume
(in gallons)
Fixed-Price Commodity Sale Commitments:
 
 
 
 
 
 
 
 
2018 (three months)
 
$
63,247

 
1,149

 
$
94,582

 
103,982

2019
 

 

 
9,521

 
12,298

2020
 

 

 
162

 
215

Total
 
$
63,247

 
1,149

 
$
104,265

 
116,495

 
 
 
 
 
 
 
 
 
Index-Price Commodity Sale Commitments:
 
 
 
 
 
 
 
 
2018 (three months)
 
$
468,661

 
7,872

 
$
285,758

 
247,918

2019
 
389,596

 
7,311

 
7,914

 
7,685

2020
 
59,885

 
1,070

 

 

Total
 
$
918,142

 
16,253

 
$
293,672

 
255,603


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

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

Note 10 —Equity

Partnership Equity

The Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest, which consists of common units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest. Our general partner is not required to guarantee or pay any of our debts and obligations.

General Partner Contributions

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

Common Unit Repurchase Program

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


28

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Our Distributions

The following table summarizes distributions declared on our common units during the last four quarters:
Date Declared
 
Record Date
 
Date Paid/Payable
 
Amount Per Unit
 
Amount Paid/Payable to Limited Partners
 
Amount Paid/Payable to General Partner
 
 
 
 
 
 
 
 
(in thousands)
 
(in thousands)
April 24, 2017
 
May 8, 2017
 
May 15, 2017
 
$
0.3900

 
$
46,870

 
$
80

July 20, 2017
 
August 4, 2017
 
August 14, 2017
 
$
0.3900

 
$
47,460

 
$
81

October 19, 2017
 
November 6, 2017
 
November 14, 2017
 
$
0.3900

 
$
47,000

 
$
81

January 23, 2018
 
February 6, 2018
 
February 14, 2018
 
$
0.3900

 
$
47,223

 
$
81


Class A Convertible Preferred Units

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

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

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

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

The following table summarizes distributions declared on our Class A Preferred Units during the last four quarters:
 
 
 
 
Amount Paid/Payable to Class A
Date Declared
 
Date Paid/Payable
 
Preferred Unitholders
 
 
 
 
(in thousands)
April 24, 2017
 
May 15, 2017
 
$
6,449

July 20, 2017
 
August 14, 2017
 
$
6,449

October 19, 2017
 
November 14, 2017
 
$
6,449

January 23, 2018
 
February 14, 2018
 
$
6,449


Class B Preferred Units

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

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

29

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


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

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

Amended and Restated Partnership Agreement

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

At-The-Market Program

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

Equity-Based Incentive Compensation

Our general partner has adopted a long-term incentive plan (“LTIP”), which allows for the issuance of equity-based compensation. Our general partner has granted certain restricted units to employees and directors, which vest in tranches, subject to the continued service of the recipients. The awards may also vest upon a change of control, at the discretion of the board of directors of our general partner. No distributions accrue to or are paid on the restricted units during the vesting period.

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

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

The following table summarizes the Service Award activity during the nine months ended December 31, 2017 :
Unvested Service Award units at March 31, 2017
 
2,708,500

Units granted
 
1,036,202

Units vested and issued
 
(1,855,102
)
Units forfeited
 
(90,000
)
Unvested Service Award units at December 31, 2017
 
1,799,600



30

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


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

The following table summarizes the scheduled vesting of our unvested Service Award units at December 31, 2017 :
Fiscal Year Ending March 31,
 
 
2018 (three months)
 
315,500

2019
 
896,750

2020
 
584,600

2021
 
2,750

Total
 
1,799,600


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

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

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

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

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

Fiscal Year Ending March 31,
 
 
2018 (three months)
 
$
3,586

2019
 
8,909

2020
 
3,175

2021
 
18

Total
 
$
15,688


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

31

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


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

The following table summarizes the Performance Award activity during the nine months ended December 31, 2017 :
Unvested Performance Award units at March 31, 2017
 
1,189,000

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


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

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

The following table summarizes the estimated future expense we expect to record on the unvested Performance Award units at December 31, 2017 (in thousands):
Fiscal Year Ending March 31,
 
 
2018 (three months)
 
$
1,266

2019
 
3,078

2020
 
624

Total
 
$
4,968


At December 31, 2017 , approximately 2.4 million common units remain available for issuance under the LTIP.

Note 11 —Fair Value of Financial Instruments

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


32

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Commodity Derivatives

The following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported in our unaudited condensed consolidated balance sheet at the dates indicated:
 
 
December 31, 2017
 
March 31, 2017
 
 
Derivative
Assets
 
Derivative
Liabilities
 
Derivative
Assets
 
Derivative
Liabilities

 
(in thousands)
Level 1 measurements
 
$
9,981

 
$
(41,702
)
 
$
2,590

 
$
(21,113
)
Level 2 measurements
 
33,645

 
(37,382
)
 
38,729

 
(27,799
)

 
43,626

 
(79,084
)
 
41,319

 
(48,912
)
 
 
 
 
 
 
 
 
 
Netting of counterparty contracts (1)
 
(8,470
)
 
8,470

 
(1,508
)
 
1,508

Net cash collateral (held) provided
 
(791
)
 
33,233

 
(1,035
)
 
19,604

Commodity derivatives
 
$
34,365

 
$
(37,381
)
 
$
38,776

 
$
(27,800
)
 
(1)
Relates to commodity derivative assets and liabilities that are expected to be net settled on an exchange or through a netting arrangement with the counterparty.

The following table summarizes the accounts that include our commodity derivative assets and liabilities in our unaudited condensed consolidated balance sheets at the dates indicated:
 
 
December 31, 2017
 
March 31, 2017
 
 
(in thousands)
Prepaid expenses and other current assets
 
$
34,283

 
$
38,711

Other noncurrent assets
 
82

 
65

Accrued expenses and other payables
 
(34,713
)
 
(27,622
)
Other noncurrent liabilities
 
(2,668
)
 
(178
)
Net commodity derivative (liability) asset
 
$
(3,016
)
 
$
10,976



33

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


The following table summarizes our open commodity derivative contract positions at the dates indicated. We do not account for these derivatives as hedges.
Contracts
 
Settlement Period
 
Net Long
(Short)
Notional Units
(in barrels)
 
Fair Value
of
Net Assets
(Liabilities)
 
 
 
 
(in thousands)
At December 31, 2017:
 
 
 
 
 
 
Cross-commodity (1)
 
January 2018–March 2018
 
(21
)
 
$
(1,587
)
Crude oil fixed-price (2)
 
January 2018–December 2019
 
(1,243
)
 
(7,536
)
Propane fixed-price (2)
 
January 2018–December 2018
 
210

 
1,942

Refined products fixed-price (2)
 
January 2018–January 2020
 
(4,743
)
 
(29,363
)
Refined products index (2)
 
January 2018–June 2018
 
(13
)
 
(51
)
Other
 
January 2018–March 2022
 
 
 
1,137

 
 
 
 
 
 
(35,458
)
Net cash collateral provided
 
 
 
 
 
32,442

Net commodity derivative liability
 
 
 
 
 
$
(3,016
)
 
 
 
 
 
 
 
At March 31, 2017:
 
 
 
 
 
 
Crude oil fixed-price (2)
 
April 2017–May 2017
 
(800
)
 
$
(55
)
Propane fixed-price (2)
 
April 2017–December 2018
 
220

 
1,082

Refined products fixed-price (2)
 
April 2017–January 2019
 
(4,682
)
 
(7,729
)
Refined products index (2)
 
April 2017–December 2017
 
(18
)
 
(103
)
Other
 
April 2017–March 2022
 
 
 
(788
)
 
 
 
 
 
 
(7,593
)
Net cash collateral provided
 
 
 
 
 
18,569

Net commodity derivative asset
 
 
 
 
 
$
10,976

 
(1)
We may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. These contracts are derivatives we have entered into as an economic hedge against the risk of one commodity price moving relative to another commodity price.
(2)
We may have fixed price physical purchases, including inventory, offset by floating price physical sales or floating price physical purchases offset by fixed price physical sales. These contracts are derivatives we have entered into as an economic hedge against the risk of mismatches between fixed and floating price physical obligations.

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

Credit Risk

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


34

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Interest Rate Risk

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At December 31, 2017 , we had $1.1 billion of outstanding borrowings under our Revolving Credit Facility at a weighted average interest rate of 4.90% .

Fair Value of Fixed-Rate Notes

The following table provides fair value estimates of our fixed-rate notes at December 31, 2017 (in thousands):
Senior unsecured notes:
 
5.125% Notes due 2019
$
367,997

6.875% Notes due 2021
$
374,045

7.500% Notes due 2023
$
681,621

6.125% Notes due 2025
$
405,804


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

Note 12—Segments

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

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

35

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


 
 
Three Months Ended December 31,
 
Nine Months Ended December 31,
 
 
2017
 
2016
 
2017
 
2016
 
 
(in thousands)
Revenues:
 
 
 
 
 
 
 
 
Crude Oil Logistics:
 
 
 
 
 
 
 
 
Crude oil sales
 
$
556,001

 
$
366,569

 
$
1,446,560

 
$
1,123,169

Crude oil transportation and other
 
33,017

 
20,914

 
89,318

 
43,020

Elimination of intersegment sales
 
(4,011
)
 
(1,577
)
 
(8,934
)
 
(4,447
)
Total Crude Oil Logistics revenues
 
585,007

 
385,906

 
1,526,944

 
1,161,742

Water Solutions:
 
 
 
 
 
 
 
 
Service fees
 
41,045

 
28,268

 
109,648

 
82,493

Recovered hydrocarbons
 
17,021

 
6,387

 
37,427

 
19,264

Other revenues
 
5,958

 
5,704

 
14,948

 
14,088

Total Water Solutions revenues
 
64,024

 
40,359

 
162,023

 
115,845

Liquids:
 
 
 
 
 
 
 
 
Propane sales
 
403,236

 
260,562

 
733,684

 
458,646

Butane sales
 
228,535

 
146,514

 
408,312

 
267,769

Other product sales
 
123,677

 
89,225

 
310,389

 
217,405

Other revenues
 
6,166

 
7,704

 
16,106

 
22,926

Elimination of intersegment sales
 
(52,570
)
 
(33,730
)
 
(88,510
)
 
(57,162
)
Total Liquids revenues
 
709,044

 
470,275

 
1,379,981

 
909,584

Retail Propane:
 
 
 
 
 
 
 
 
Propane sales
 
124,466

 
96,699

 
221,102

 
174,510

Distillate sales
 
22,806

 
19,569

 
39,037

 
35,613

Other revenues
 
12,797

 
12,418

 
31,733

 
30,056

Elimination of intersegment sales
 
(44
)
 
(32
)
 
(75
)
 
(48
)
Total Retail Propane revenues
 
160,025

 
128,654

 
291,797

 
240,131

Refined Products and Renewables:
 
 
 
 
 
 
 
 
Refined products sales
 
2,845,482

 
2,258,317

 
8,493,357

 
6,409,889

Renewables sales
 
99,436

 
123,065

 
313,366

 
325,377

Service fees
 
94

 
50

 
262

 
11,195

Elimination of intersegment sales
 
(138
)
 
(149
)
 
(268
)
 
(293
)
Total Refined Products and Renewables revenues
 
2,944,874

 
2,381,283

 
8,806,717

 
6,746,168

Corporate and Other
 
289

 
164

 
696

 
679

Total revenues
 
$
4,463,263

 
$
3,406,641

 
$
12,168,158

 
$
9,174,149

Depreciation and Amortization:
 
 
 
 
 
 
 
 
Crude Oil Logistics
 
$
20,092

 
$
16,503

 
$
61,885

 
$
34,496

Water Solutions
 
24,586

 
27,150

 
73,847

 
76,713

Liquids
 
6,247

 
4,441

 
18,718

 
13,315

Retail Propane
 
11,130

 
11,379

 
34,205

 
31,771

Refined Products and Renewables
 
323

 
404

 
971

 
1,237

Corporate and Other
 
962

 
890

 
2,801

 
2,744

Total depreciation and amortization
 
$
63,340

 
$
60,767

 
$
192,427

 
$
160,276

Operating Income (Loss):
 
 
 
 
 
 
 
 
Crude Oil Logistics
 
$
106,279

 
$
(9,163
)
 
$
111,832

 
$
(28,827
)
Water Solutions
 
(1,373
)
 
(11,898
)
 
(10,075
)
 
63,136

Liquids
 
22,290

 
24,765

 
(104,589
)
 
33,092

Retail Propane
 
23,972

 
21,772

 
8,878

 
10,553

Refined Products and Renewables
 
(4,791
)
 
8,209

 
30,747

 
169,365

Corporate and Other
 
(21,846
)
 
(11,128
)
 
(56,031
)
 
(66,690
)
Total operating income (loss)
 
$
124,531

 
$
22,557

 
$
(19,238
)
 
$
180,629



36

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



The following table summarizes additions to property, plant and equipment and intangible assets by segment for the periods indicated. This information has been prepared on the accrual basis, and includes property, plant and equipment and intangible assets acquired in acquisitions.
 
 
Three Months Ended December 31,
 
Nine Months Ended December 31,
 
 
2017
 
2016
 
2017
 
2016
 
 
(in thousands)
Crude Oil Logistics
 
$
14,788

 
$
42,758

 
$
26,509

 
$
147,460

Water Solutions
 
22,556

 
18,275

 
56,996

 
86,628

Liquids
 
1,188

 
1,736

 
2,868

 
14,897

Retail Propane
 
14,527

 
16,196

 
49,242

 
94,170

Refined Products and Renewables
 

 
(945
)
 

 
42,175

Corporate and Other
 
625

 
375

 
1,334

 
2,107

Total
 
$
53,684

 
$
78,395

 
$
136,949

 
$
387,437


The following tables summarize long-lived assets (consisting of property, plant and equipment, intangible assets, and goodwill) and total assets by segment at the dates indicated:
 
 
December 31, 2017
 
March 31, 2017
 
 
(in thousands)
Long-lived assets, net:
 
 
 
 
Crude Oil Logistics
 
$
1,661,020

 
$
1,724,805

Water Solutions
 
1,239,578

 
1,261,944

Liquids
 
485,454

 
619,204

Retail Propane
 
457,031

 
547,960

Refined Products and Renewables
 
210,534

 
215,637

Corporate and Other
 
33,338

 
36,395

Total
 
$
4,086,955

 
$
4,405,945

 
 
 
 
 
Total assets:
 
 
 
 
Crude Oil Logistics
 
$
2,269,632

 
$
2,538,768

Water Solutions
 
1,303,873

 
1,301,415

Liquids
 
901,904

 
767,597

Retail Propane
 
660,850

 
622,859

Refined Products and Renewables
 
1,087,499

 
988,073

Corporate and Other
 
92,628

 
101,667

Total
 
$
6,316,386

 
$
6,320,379


Note 13 —Transactions with Affiliates

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

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

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

37

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



The following table summarizes these related party transactions for the periods indicated:
 
 
Three Months Ended December 31,
 
Nine Months Ended December 31,
 
 
2017
 
2016
 
2017
 
2016
 
 
(in thousands)
Sales to SemGroup
 
$
178

 
$
150

 
$
408

 
$
3,734

Purchases from SemGroup
 
$
1,050

 
$
1,911

 
$
3,978

 
$
5,874

Sales to equity method investees
 
$
98

 
$
95

 
$
294

 
$
595

Purchases from equity method investees
 
$
18,373

 
$
33,538

 
$
66,842

 
$
91,530

Sales to entities affiliated with management
 
$
64

 
$
53

 
$
204

 
$
205

Purchases from entities affiliated with management
 
$
193

 
$
2,580

 
$
1,540

 
$
14,316


Accounts receivable from affiliates consist of the following at the dates indicated:
 
 
December 31, 2017
 
March 31, 2017
 
 
(in thousands)
Receivables from SemGroup
 
$
83

 
$
6,668

Receivables from NGL Energy Holdings LLC
 
3,413

 

Receivables from equity method investees
 
2

 
15

Receivables from entities affiliated with management
 
19

 
28

Total
 
$
3,517

 
$
6,711


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

Accounts payable to affiliates consist of the following at the dates indicated:
 
 
December 31, 2017
 
March 31, 2017
 
 
(in thousands)
Payables to SemGroup
 
$
390

 
$
6,571

Payables to equity method investees
 
81

 
1,306

Payables to entities affiliated with management
 
3

 
41

Total
 
$
474

 
$
7,918


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

Other Related Party Transactions

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

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

38

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Current assets
$
276

Property, plant and equipment
1,366

Intangible assets (customer relationships)
4,782

Fair value of net assets acquired
$
6,424


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

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

Note 14 —Assets and Liabilities Held for Sale

Potential Sale of a Portion of Retail Propane Business

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

The following table summarizes the major classes of assets and liabilities classified as held for sale at December 31, 2017 (in thousands):
Assets Held for Sale
 
 
Cash and cash equivalents
 
$
1,985

Accounts receivable-trade, net
 
13,336

Accounts receivable-affiliates
 
1

Inventories
 
6,273

Prepaid expenses and other current assets
 
2,437

Property, plant and equipment, net
 
61,137

Goodwill
 
24,959

Intangible assets, net
 
21,463

Total assets held for sale
 
$
131,591

 
 
 
Liabilities Held for Sale
 
 
Accounts payable-trade
 
$
686

Accrued expenses and other payables
 
2,565

Advance payments received from customers
 
13,163

Other liabilities
 
160

Total liabilities held for sale
 
$
16,574


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

39

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


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

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

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

During the periods presented in the tables below, the status of certain subsidiaries changed, in that they either became guarantors of or ceased to be guarantors of the senior unsecured notes.

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

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

40

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Balance Sheet
(in Thousands)
 
 
December 31, 2017
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
CURRENT ASSETS:
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
14,994

 
$

 
$
11,179

 
$
2,296

 
$

 
$
28,469

Accounts receivable-trade, net of allowance for doubtful accounts
 

 

 
1,060,207

 
3,700

 

 
1,063,907

Accounts receivable-affiliates
 

 

 
3,517

 

 

 
3,517

Inventories
 

 

 
644,154

 
946

 

 
645,100

Prepaid expenses and other current assets
 

 

 
97,058

 
337

 

 
97,395

Assets held for sale
 

 

 
131,742

 

 
(151
)
 
131,591

Total current assets
 
14,994

 

 
1,947,857

 
7,279

 
(151
)
 
1,969,979

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation
 

 

 
1,676,248

 
32,435

 

 
1,708,683

GOODWILL
 

 

 
1,300,560

 
12,757

 

 
1,313,317

INTANGIBLE ASSETS, net of accumulated amortization
 

 

 
1,051,683

 
13,272

 

 
1,064,955

INVESTMENTS IN UNCONSOLIDATED ENTITIES
 

 

 
16,369

 

 

 
16,369

NET INTERCOMPANY RECEIVABLES (PAYABLES)
 
2,116,433

 

 
(2,095,213
)
 
(21,220
)
 

 

INVESTMENTS IN CONSOLIDATED SUBSIDIARIES
 
1,727,675

 

 
24,623

 

 
(1,752,298
)
 

LOAN RECEIVABLE-AFFILIATE
 

 

 
318

 

 

 
318

OTHER NONCURRENT ASSETS
 

 

 
242,765

 

 

 
242,765

Total assets
 
$
3,859,102

 
$

 
$
4,165,210

 
$
44,523

 
$
(1,752,449
)
 
$
6,316,386

LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
CURRENT LIABILITIES:
 
 
 
 
 
 
 
 
 
 
 
 
Accounts payable-trade
 
$

 
$

 
$
865,117

 
$
1,651

 
$

 
$
866,768

Accounts payable-affiliates
 
1

 

 
473

 

 

 
474

Accrued expenses and other payables
 
34,879

 

 
194,937

 
936

 

 
230,752

Advance payments received from customers
 

 

 
46,326

 
675

 
(151
)
 
46,850

Current maturities of long-term debt
 

 

 
2,887

 
373

 

 
3,260

Liabilities held for sale
 

 

 
16,574

 

 

 
16,574

Total current liabilities
 
34,880

 

 
1,126,314

 
3,635

 
(151
)
 
1,164,678

LONG-TERM DEBT, net of debt issuance costs and current maturities
 
1,774,042

 

 
1,147,180

 
744

 

 
2,921,966

OTHER NONCURRENT LIABILITIES
 

 

 
164,041

 
4,240

 

 
168,281

CLASS A 10.75% CONVERTIBLE PREFERRED UNITS
 
76,056

 

 

 

 

 
76,056

REDEEMABLE NONCONTROLLING INTEREST
 

 

 

 
4,011

 

 
4,011

EQUITY:
 
 
 
 
 
 
 
 
 
 
 
 
Partners’ equity
 
1,974,124

 

 
1,728,919

 
32,127

 
(1,759,568
)
 
1,975,602

Accumulated other comprehensive loss
 

 

 
(1,244
)
 
(234
)
 

 
(1,478
)
Noncontrolling interests
 

 

 

 

 
7,270

 
7,270

Total equity
 
1,974,124

 

 
1,727,675

 
31,893

 
(1,752,298
)
 
1,981,394

Total liabilities and equity
 
$
3,859,102

 
$

 
$
4,165,210

 
$
44,523

 
$
(1,752,449
)
 
$
6,316,386


41

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Balance Sheet
(in Thousands)
 
 
March 31, 2017
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
CURRENT ASSETS:
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
6,257

 
$

 
$
2,903

 
$
3,104

 
$

 
$
12,264

Accounts receivable-trade, net of allowance for doubtful accounts
 

 

 
795,479

 
5,128

 

 
800,607

Accounts receivable-affiliates
 

 

 
6,711

 

 

 
6,711

Inventories
 

 

 
560,769

 
663

 

 
561,432

Prepaid expenses and other current assets
 

 

 
102,703

 
490

 

 
103,193

Total current assets
 
6,257

 

 
1,468,565

 
9,385

 

 
1,484,207

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation
 

 

 
1,725,383

 
64,890

 

 
1,790,273

GOODWILL
 

 

 
1,437,759

 
13,957

 

 
1,451,716

INTANGIBLE ASSETS, net of accumulated amortization
 

 

 
1,149,524

 
14,432

 

 
1,163,956

INVESTMENTS IN UNCONSOLIDATED ENTITIES
 

 

 
187,423

 

 

 
187,423

NET INTERCOMPANY RECEIVABLES (PAYABLES)
 
2,424,730

 

 
(2,408,189
)
 
(16,541
)
 

 

INVESTMENTS IN CONSOLIDATED SUBSIDIARIES
 
1,978,158

 

 
47,598

 

 
(2,025,756
)
 

LOAN RECEIVABLE-AFFILIATE
 

 

 
3,200

 

 

 
3,200

OTHER NONCURRENT ASSETS
 

 

 
239,436

 
168

 

 
239,604

Total assets
 
$
4,409,145

 
$

 
$
3,850,699

 
$
86,291

 
$
(2,025,756
)
 
$
6,320,379

LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
CURRENT LIABILITIES:
 
 
 
 
 
 
 
 
 
 
 
 
Accounts payable-trade
 
$

 
$

 
$
657,077

 
$
944

 
$

 
$
658,021

Accounts payable-affiliates
 
1

 

 
7,907

 
10

 

 
7,918

Accrued expenses and other payables
 
42,150

 

 
164,012

 
963

 

 
207,125

Advance payments received from customers
 

 

 
35,107

 
837

 

 
35,944

Current maturities of long-term debt
 
25,000

 

 
4,211

 
379

 

 
29,590

Total current liabilities
 
67,151

 

 
868,314

 
3,133

 

 
938,598

LONG-TERM DEBT, net of debt issuance costs and current maturities
 
2,138,048

 

 
824,370

 
1,065

 

 
2,963,483

OTHER NONCURRENT LIABILITIES
 

 

 
179,857

 
4,677

 

 
184,534

CLASS A 10.75% CONVERTIBLE PREFERRED UNITS
 
63,890

 

 

 

 

 
63,890

REDEEMABLE NONCONTROLLING INTEREST
 

 

 

 
3,072

 

 
3,072

EQUITY:
 
 
 
 
 
 
 
 
 
 
 
 
Partners’ equity
 
2,140,056

 

 
1,979,785

 
74,545

 
(2,052,502
)
 
2,141,884

Accumulated other comprehensive loss
 

 

 
(1,627
)
 
(201
)
 

 
(1,828
)
Noncontrolling interests
 

 

 

 

 
26,746

 
26,746

Total equity
 
2,140,056

 

 
1,978,158

 
74,344

 
(2,025,756
)
 
2,166,802

Total liabilities and equity
 
$
4,409,145

 
$

 
$
3,850,699

 
$
86,291

 
$
(2,025,756
)
 
$
6,320,379



42

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Statement of Operations
(in Thousands)
 
 
Three Months Ended December 31, 2017
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
 
 
REVENUES
 
$

 
$

 
$
4,454,133

 
$
10,818

 
$
(1,688
)
 
$
4,463,263

COST OF SALES
 

 

 
4,269,586

 
4,910

 
(1,688
)
 
4,272,808

OPERATING COSTS AND EXPENSES:
 
 
 
 
 
 
 
 
 
 
 
 
Operating
 

 

 
82,468

 
2,378

 

 
84,846

General and administrative
 

 

 
29,033

 
185

 

 
29,218

Depreciation and amortization
 

 

 
61,961

 
1,379

 

 
63,340

(Gain) loss on disposal or impairment of assets, net
 

 

 
(111,509
)
 
29

 

 
(111,480
)
Operating Income
 

 

 
122,594

 
1,937

 

 
124,531

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
 
 
 
 
 
Equity in earnings of unconsolidated entities
 

 

 
3,426

 

 

 
3,426

Interest expense
 
(36,019
)
 

 
(15,752
)
 
(228
)
 
209

 
(51,790
)
Loss on early extinguishment of liabilities, net
 
(21,141
)
 

 

 

 

 
(21,141
)
Other income, net
 

 

 
2,298

 
18

 
(209
)
 
2,107

(Loss) Income Before Income Taxes
 
(57,160
)
 

 
112,566

 
1,727

 

 
57,133

INCOME TAX EXPENSE
 

 

 
(364
)
 

 

 
(364
)
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES
 
113,416

 

 
1,214

 

 
(114,630
)
 

Net Income
 
56,256

 

 
113,416

 
1,727

 
(114,630
)
 
56,769

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
 
 
 
 
 
 
 
 
(89
)
 
(89
)
LESS: NET INCOME ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS
 
 
 
 
 
 
 
 
 
(424
)
 
(424
)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS
 
 
 
 
 
 
 
 
 
(16,219
)
 
(16,219
)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER
 
 
 
 
 
 
 
 
 
(73
)
 
(73
)
NET INCOME ALLOCATED TO COMMON UNITHOLDERS
 
$
56,256

 
$

 
$
113,416

 
$
1,727

 
$
(131,435
)
 
$
39,964


43

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Statement of Operations
(in Thousands)
 
 
Three Months Ended December 31, 2016
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
 
 
REVENUES
 
$

 
$

 
$
3,393,541

 
$
14,249

 
$
(1,149
)
 
$
3,406,641

COST OF SALES
 

 

 
3,226,175

 
2,996

 
(1,149
)
 
3,228,022

OPERATING COSTS AND EXPENSES:
 
 
 
 
 
 
 
 
 
 
 
 
Operating
 

 

 
72,911

 
4,070

 

 
76,981

General and administrative
 

 

 
18,090

 
190

 

 
18,280

Depreciation and amortization
 

 

 
58,091

 
2,676

 

 
60,767

Loss (gain) on disposal or impairment of assets, net
 

 

 
37

 
(3
)
 

 
34

Operating Income
 

 

 
18,237

 
4,320

 

 
22,557

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
 
 
 
 
 
Equity in earnings of unconsolidated entities
 

 

 
1,279

 

 

 
1,279

Interest expense
 
(26,217
)
 

 
(15,340
)
 
(98
)
 
219

 
(41,436
)
Other income, net
 

 

 
20,206

 
20

 
(219
)
 
20,007

(Loss) Income Before Income Taxes
 
(26,217
)
 

 
24,382

 
4,242

 

 
2,407

INCOME TAX EXPENSE
 

 

 
(1,114
)
 

 

 
(1,114
)
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES
 
27,193

 

 
3,925

 

 
(31,118
)
 

Net Income
 
976

 

 
27,193

 
4,242

 
(31,118
)
 
1,293

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
 
 
 
 
 
 
 
 
(317
)
 
(317
)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS
 
 
 
 
 
 
 
 
 
(8,906
)
 
(8,906
)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER
 
 
 
 
 
 
 
 
 
(22
)
 
(22
)
NET INCOME ALLOCATED TO COMMON UNITHOLDERS
 
$
976

 
$

 
$
27,193

 
$
4,242

 
$
(40,363
)
 
$
(7,952
)

44

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Statement of Operations
(in Thousands)
 
 
Nine Months Ended December 31, 2017
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
 
 
REVENUES
 
$

 
$

 
$
12,150,896

 
$
20,261

 
$
(2,999
)
 
$
12,168,158

COST OF SALES
 

 

 
11,679,386

 
9,250

 
(2,999
)
 
11,685,637

OPERATING COSTS AND EXPENSES:
 
 

 
 

 
 

 
 

 
 

 
 

Operating
 

 

 
231,376

 
5,909

 

 
237,285

General and administrative
 

 

 
77,190

 
499

 

 
77,689

Depreciation and amortization
 

 

 
188,893

 
3,534

 

 
192,427

(Gain) loss on disposal or impairment of assets, net
 

 

 
(12,436
)
 
1,194

 

 
(11,242
)
Revaluation of liabilities
 

 

 
5,600

 

 

 
5,600

Operating Loss
 

 

 
(19,113
)
 
(125
)
 

 
(19,238
)
OTHER INCOME (EXPENSE):
 
 

 
 

 
 

 
 

 
 

 
 

Equity in earnings of unconsolidated entities
 

 

 
7,270

 

 

 
7,270

Interest expense
 
(111,609
)
 

 
(39,576
)
 
(681
)
 
617

 
(151,249
)
Loss on early extinguishment of liabilities, net
 
(22,479
)
 

 

 

 

 
(22,479
)
Other income, net
 

 

 
6,656

 
74

 
(617
)
 
6,113

Loss Before Income Taxes
 
(134,088
)
 

 
(44,763
)
 
(732
)
 

 
(179,583
)
INCOME TAX EXPENSE
 

 

 
(934
)
 

 

 
(934
)
EQUITY IN NET LOSS OF CONSOLIDATED SUBSIDIARIES
 
(46,389
)
 

 
(692
)
 

 
47,081

 

Net Loss
 
(180,477
)
 

 
(46,389
)
 
(732
)
 
47,081

 
(180,517
)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
 

 
 

 
 

 
 

 
(221
)
 
(221
)
LESS: NET LOSS ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS
 
 
 
 
 
 
 
 
 
261

 
261

LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS
 
 
 
 
 
 
 
 
 
(42,001
)
 
(42,001
)
LESS: NET LOSS ALLOCATED TO GENERAL PARTNER
 
 
 
 
 
 
 
 
 
121

 
121

LESS: REPURCHASE OF WARRANTS
 
 
 
 
 
 
 
 
 
(349
)
 
(349
)
NET LOSS ALLOCATED TO COMMON UNITHOLDERS
 
$
(180,477
)
 
$

 
$
(46,389
)
 
$
(732
)
 
$
4,892

 
$
(222,706
)


45

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Statement of Operations
(in Thousands)
 
 
Nine Months Ended December 31, 2016
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
 
 
REVENUES
 
$

 
$

 
$
9,142,575

 
$
33,718

 
$
(2,144
)
 
$
9,174,149

COST OF SALES
 

 

 
8,720,039

 
5,297

 
(2,144
)
 
8,723,192

OPERATING COSTS AND EXPENSES:
 
 

 
 

 
 

 
 

 
 

 
 

Operating
 

 

 
212,542

 
12,866

 

 
225,408

General and administrative
 

 

 
87,402

 
675

 

 
88,077

Depreciation and amortization
 

 

 
152,140

 
8,136

 

 
160,276

Gain on disposal or impairment of assets, net
 

 

 
(203,406
)
 
(27
)
 

 
(203,433
)
Operating Income
 

 

 
173,858

 
6,771

 

 
180,629

OTHER INCOME (EXPENSE):
 
 

 
 

 
 

 
 

 
 

 
 

Equity in earnings of unconsolidated entities
 

 

 
1,726

 

 

 
1,726

Revaluation of investments
 

 

 
(14,365
)
 

 

 
(14,365
)
Interest expense
 
(58,907
)
 

 
(46,238
)
 
(551
)
 
380

 
(105,316
)
Gain on early extinguishment of liabilities, net
 
8,614

 

 
22,276

 

 

 
30,890

Other income, net
 

 

 
26,196

 
44

 
(380
)
 
25,860

(Loss) Income Before Income Taxes
 
(50,293
)
 

 
163,453

 
6,264

 

 
119,424

INCOME TAX EXPENSE
 

 

 
(2,036
)
 

 

 
(2,036
)
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES
 
161,590

 

 
173

 

 
(161,763
)
 

Net Income
 
111,297

 

 
161,590

 
6,264

 
(161,763
)
 
117,388

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
 
 
 
 
 
 
 
 
(6,091
)
 
(6,091
)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS
 
 
 
 
 
 
 
 
 
(20,958
)
 
(20,958
)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER
 
 

 
 

 
 

 
 

 
(180
)
 
(180
)
NET INCOME ALLOCATED TO COMMON UNITHOLDERS
 
$
111,297

 
$

 
$
161,590

 
$
6,264

 
$
(188,992
)
 
$
90,159


46

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Statements of Comprehensive Income (Loss)
(in Thousands)
 
 
Three Months Ended December 31, 2017
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
Net income
 
$
56,256

 
$

 
$
113,416

 
$
1,727

 
$
(114,630
)
 
$
56,769

Other comprehensive inco me (loss)
 

 

 
795

 
(11
)
 

 
784

Comprehensive income
 
$
56,256

 
$

 
$
114,211

 
$
1,716

 
$
(114,630
)
 
$
57,553


 
 
Three Months Ended December 31, 2016
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
Net income
 
$
976

 
$

 
$
27,193

 
$
4,242

 
$
(31,118
)
 
$
1,293

Other comprehensive income (loss)
 

 

 
568

 
(23
)
 

 
545

Comprehensive income
 
$
976

 
$

 
$
27,761

 
$
4,219

 
$
(31,118
)
 
$
1,838


 
 
Nine Months Ended December 31, 2017
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
Net loss
 
$
(180,477
)
 
$

 
$
(46,389
)
 
$
(732
)
 
$
47,081

 
$
(180,517
)
Other comprehensive inco me (loss)
 

 

 
383

 
(33
)
 

 
350

Comprehensive loss
 
$
(180,477
)
 
$

 
$
(46,006
)
 
$
(765
)
 
$
47,081

 
$
(180,167
)

 
 
Nine Months Ended December 31, 2016
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
Net income
 
$
111,297

 
$

 
$
161,590

 
$
6,264

 
$
(161,763
)
 
$
117,388

Other comprehensive income (loss)
 

 

 
93

 
(33
)
 

 
60

Comprehensive income
 
$
111,297

 
$

 
$
161,683

 
$
6,231

 
$
(161,763
)
 
$
117,448



47

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Statement of Cash Flows
(in Thousands)
 
 
Nine Months Ended December 31, 2017
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidated
OPERATING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
 
$
415,012

 
$

 
$
(447,316
)
 
$
36,365

 
$
4,061

INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Capital expenditures
 

 

 
(97,971
)
 
(1,413
)
 
(99,384
)
Acquisitions, net of cash acquired
 

 

 
(49,081
)
 
(400
)
 
(49,481
)
Cash flows from settlements of commodity derivatives
 

 

 
(85,823
)
 

 
(85,823
)
Proceeds from sales of assets
 

 

 
33,673

 

 
33,673

Proceeds from sale of interest in Glass Mountain
 

 

 
292,117

 

 
292,117

Transaction with an unconsolidated entity (Note 13)
 

 

 
(6,424
)
 

 
(6,424
)
Investments in unconsolidated entities
 

 

 
(21,461
)
 

 
(21,461
)
Distributions of capital from unconsolidated entities
 

 

 
11,710

 

 
11,710

Repayments on loan for natural gas liquids facility
 

 

 
7,425

 

 
7,425

Loan to affiliate
 

 

 
(1,460
)
 

 
(1,460
)
Repayments on loan to affiliate
 

 

 
4,160

 

 
4,160

Other (Note 14)
 

 

 
20,000

 

 
20,000

Net cash provided by (used in) investing activities
 

 

 
106,865

 
(1,813
)
 
105,052

FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Proceeds from borrowings under Revolving Credit Facility
 

 

 
1,674,500

 

 
1,674,500

Payments on Revolving Credit Facility
 

 

 
(1,349,500
)
 

 
(1,349,500
)
Repayment and repurchase of senior secured and senior unsecured notes
 
(415,568
)
 

 

 

 
(415,568
)
Payments on other long-term debt
 

 

 
(3,971
)
 
(390
)
 
(4,361
)
Debt issuance costs
 
(693
)
 

 
(1,804
)
 

 
(2,497
)
Contributions from noncontrolling interest owners, net
 

 

 

 
23

 
23

Distributions to general and common unit partners and preferred unitholders
 
(166,589
)
 

 

 

 
(166,589
)
Distributions to noncontrolling interest owners
 

 

 

 
(3,082
)
 
(3,082
)
Proceeds from sale of preferred units, net of offering costs
 
202,731

 

 

 

 
202,731

Repurchase of warrants
 
(10,549
)
 

 

 

 
(10,549
)
Common unit repurchases and cancellations
 
(15,608
)
 

 

 

 
(15,608
)
Payments for settlement and early extinguishment of liabilities
 

 

 
(2,408
)
 

 
(2,408
)
Net changes in advances with consolidated entities
 
1

 

 
31,910

 
(31,911
)
 

Net cash (used in) provided by financing activities
 
(406,275
)
 

 
348,727

 
(35,360
)
 
(92,908
)
Net increase (decrease) in cash and cash equivalents
 
8,737

 

 
8,276

 
(808
)
 
16,205

Cash and cash equivalents, beginning of period
 
6,257

 

 
2,903

 
3,104

 
12,264

Cash and cash equivalents, end of period
 
$
14,994

 
$

 
$
11,179

 
$
2,296

 
$
28,469


48

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Statement of Cash Flows
(in Thousands)
 
 
Nine Months Ended December 31, 2016
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidated
OPERATING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Net cash used in operating activities
 
$
(48,850
)
 
$

 
$
(63,850
)
 
$
(2,872
)
 
$
(115,572
)
INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Capital expenditures
 

 

 
(257,734
)
 
(6,846
)
 
(264,580
)
Acquisitions, net of cash acquired
 

 

 
(116,153
)
 
(11,360
)
 
(127,513
)
Cash flows from settlements of commodity derivatives
 

 

 
(82,815
)
 

 
(82,815
)
Proceeds from sales of assets
 

 

 
14,136

 
59

 
14,195

Proceeds from sale of TLP common units
 

 

 
112,370

 

 
112,370

Proceeds from sale of Grassland
 

 

 

 
22,000

 
22,000

Distributions of capital from unconsolidated entities
 

 

 
7,608

 

 
7,608

Repayments on loan for natural gas liquids facility
 

 

 
6,585

 

 
6,585

Loan to affiliate
 

 

 
(2,700
)
 

 
(2,700
)
Repayments on loan to affiliate
 

 

 
655

 

 
655

Payment to terminate development agreement
 

 

 
(16,875
)
 

 
(16,875
)
Net cash (used in) provided by investing activities
 

 

 
(334,923
)
 
3,853

 
(331,070
)
FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Proceeds from borrowings under Revolving Credit Facility
 

 

 
1,176,000

 

 
1,176,000

Payments on Revolving Credit Facility
 

 

 
(1,510,500
)
 

 
(1,510,500
)
Issuance of senior unsecured notes
 
700,000

 

 

 

 
700,000

Repurchase of senior unsecured notes
 
(15,129
)
 

 

 

 
(15,129
)
Payments on other long-term debt
 

 

 
(6,359
)
 
(190
)
 
(6,549
)
Debt issuance costs
 
(12,536
)
 

 
(72
)
 

 
(12,608
)
Contributions from general partner
 
59

 

 

 

 
59

Contributions from noncontrolling interest owners, net
 

 

 

 
639

 
639

Distributions to general and common unit partners and preferred unitholders
 
(132,135
)
 

 

 

 
(132,135
)
Distributions to noncontrolling interest owners
 

 

 

 
(3,292
)
 
(3,292
)
Proceeds from sale of preferred units, net of offering costs
 
234,989

 

 

 

 
234,989

Proceeds from sale of common units, net of offering costs
 
43,896

 

 

 

 
43,896

Payments for settlement and early extinguishment of liabilities
 

 

 
(27,977
)
 

 
(27,977
)
Net changes in advances with consolidated entities
 
(772,232
)
 

 
769,955

 
2,277

 

Net cash provided by (used in) financing activities
 
46,912

 

 
401,047

 
(566
)
 
447,393

Net (decrease) increase in cash and cash equivalents
 
(1,938
)
 

 
2,274

 
415

 
751

Cash and cash equivalents, beginning of period
 
25,749

 

 
784

 
1,643

 
28,176

Cash and cash equivalents, end of period
 
$
23,811

 
$

 
$
3,058

 
$
2,058

 
$
28,927



49



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

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

Overview

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

Our Crude Oil Logistics segment purchases crude oil from producers and transports it to refineries or for resale at pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs, and provides terminaling, trucking, marine and pipeline transportation services through its owned assets.
Our Water Solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production and for the disposal of solids such as tank bottoms and drilling fluids and performs truck and frac tank washouts. In addition, our Water Solutions segment sells the recovered hydrocarbons that result from performing these services.
Our Liquids segment supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada using its leased underground storage and fleet of leased railcars, markets regionally through its 21 owned terminals throughout the United States, and provides terminaling and storage services at its salt dome storage facility in Utah.
Our Retail Propane segment sells propane, distillates, equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 30 states and the District of Columbia.
Our Refined Products and Renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations, purchases refined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedules them for delivery at various locations throughout the country.


50

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,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Total revenues
$
4,463,263

 
$
3,406,641

 
$
12,168,158

 
$
9,174,149

Total cost of sales
4,272,808

 
3,228,022

 
11,685,637

 
8,723,192

Operating expenses
84,846

 
76,981

 
237,285

 
225,408

General and administrative expense
29,218

 
18,280

 
77,689

 
88,077

Depreciation and amortization
63,340

 
60,767

 
192,427

 
160,276

(Gain) loss on disposal or impairment of assets, net
(111,480
)
 
34

 
(11,242
)
 
(203,433
)
Revaluation of liabilities

 

 
5,600

 

Operating income (loss)
124,531

 
22,557

 
(19,238
)
 
180,629

Equity in earnings of unconsolidated entities
3,426

 
1,279

 
7,270

 
1,726

Revaluation of investments

 

 

 
(14,365
)
Interest expense
(51,790
)
 
(41,436
)
 
(151,249
)
 
(105,316
)
(Loss) gain on early extinguishment of liabilities, net
(21,141
)
 

 
(22,479
)
 
30,890

Other income, net
2,107

 
20,007

 
6,113

 
25,860

Income (loss) before income taxes
57,133

 
2,407

 
(179,583
)
 
119,424

Income tax expense
(364
)
 
(1,114
)
 
(934
)
 
(2,036
)
Net income (loss)
56,769

 
1,293

 
(180,517
)
 
117,388

Less: Net income attributable to noncontrolling interests
(89
)
 
(317
)
 
(221
)
 
(6,091
)
Less: Net (income) loss attributable to redeemable noncontrolling interests
(424
)
 

 
261

 

Net income (loss) attributable to NGL Energy Partners LP
56,256

 
976

 
(180,477
)
 
111,297

Less: Distributions to preferred unitholders
(16,219
)
 
(8,906
)
 
(42,001
)
 
(20,958
)
Less: Net (income) loss allocated to general partner
(73
)
 
(22
)
 
121

 
(180
)
Less: Repurchase of warrants

 

 
(349
)
 

Net income (loss) allocated to common unitholders
$
39,964

 
$
(7,952
)
 
$
(222,706
)
 
$
90,159


Items Impacting the Comparability of Our Financial Results

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

Recent Developments

Repurchases of Senior Secured Notes

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

Repurchases of Senior Unsecured Notes

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


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Common Unit Repurchase Program

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

Tax Cuts and Jobs Act of 2017

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

We have certain taxable corporate subsidiaries in Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales. In addition, as of December 31, 2017, we do not have any deferred tax assets or liabilities. Any future deferred tax assets or liabilities will be valued based on the new corporate tax rate under the Act.

Amendment to Credit Agreement

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

Acquisitions

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

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

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

three water solutions facilities;
the remaining 25% ownership interest in three water solutions facilities;
an additional 24.5% interest in an existing produced water pipeline company;
the remaining 65% ownership interest in Grassland Water Solutions, LLC (“Grassland”), in which we subsequently sold 100% of our interest;
four retail propane businesses; and
certain natural gas liquids facilities.


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Dispositions

Potential Sale of a Portion of Retail Propane Business

On November 7, 2017, we entered into a definitive agreement with DCC LPG, a division of DCC plc, to sell a portion of our Retail Propane segment for $200 million in cash, adjusted for working capital at closing. We will retain this business through closing, which is expected to be March 31, 2018. The Retail Propane businesses subject to this transaction are comprised of our operations across the Mid-Continent and Western portions of the United States. We will retain our Retail Propane businesses located in the Eastern and Southeastern section of the United States. In November 2017, we received a deposit of $20 million from DCC LPG related to the sale which is recorded in accrued expenses and other payables in our December 31, 2017 unaudited condensed consolidated balance sheet. As part of the agreement, we issued a letter of credit to DCC LPG for the amount of their deposit.

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

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

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

 

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

Crude Oil Logistics

The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated:
 
 
Three Months Ended December 31,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per barrel amounts)
Revenues:
 
 
 
 
 
 
Crude oil sales
 
$
556,001

 
$
366,569

 
$
189,432

Crude oil transportation and other
 
33,017

 
20,914

 
12,103

Total revenues (1)
 
589,018

 
387,483

 
201,535

Expenses:
 
 

 
 

 
 

Cost of sales
 
556,882

 
363,416

 
193,466

Operating expenses
 
11,712

 
10,591

 
1,121

General and administrative expenses
 
1,627

 
1,481

 
146

Depreciation and amortization expense
 
20,092

 
16,503

 
3,589

(Gain) loss on disposal or impairment of assets, net
 
(107,574
)
 
4,655

 
(112,229
)
Total expenses
 
482,739

 
396,646

 
86,093

Segment operating income (loss)
 
$
106,279

 
$
(9,163
)
 
$
115,442

 
 
 
 
 
 
 
Crude oil sold (barrels)
 
10,006

 
7,527

 
2,479

Crude oil transported on owned pipelines (barrels)
 
9,228

 
1,610

 
7,618

Crude oil storage capacity - owned and leased (barrels) (2)
 
6,362

 
6,765

 
(403
)
Crude oil storage capacity leased to third parties (barrels) (2)
 
2,829

 
4,398

 
(1,569
)
Crude oil inventory (barrels) (2)
 
1,356

 
2,037

 
(681
)
Crude oil sold ($/barrel)
 
$
55.567

 
$
48.701

 
$
6.866

Cost per crude oil sold ($/barrel)
 
$
55.655

 
$
48.282

 
$
7.373

Crude oil product margin ($/barrel)
 
$
(0.088
)
 
$
0.419

 
$
(0.507
)
 
(1)
Revenues include $4.0 million and $1.6 million of intersegment sales during the three months ended December 31, 2017 and 2016 , respectively, that are eliminated in our unaudited condensed consolidated statements of operations.
(2)
Information is presented as of December 31, 2017 and December 31, 2016 , respectively.

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

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

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

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

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

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

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


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Water Solutions

The following table summarizes the operating results of our Water Solutions segment for the periods indicated:
 
 
Three Months Ended December 31,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per barrel and per day amounts)
Revenues:
 
 
 
 
 
 
Service fees
 
$
41,045

 
$
28,268

 
$
12,777

Recovered hydrocarbons
 
17,021

 
6,387

 
10,634

Other revenues
 
5,958

 
5,704

 
254

Total revenues
 
64,024

 
40,359

 
23,665

Expenses:
 
 
 
 
 
 
Cost of sales-derivative loss (gain)
 
9,481

 
(238
)
 
9,719

Cost of sales-other
 
711

 
715

 
(4
)
Operating expenses
 
27,041

 
21,728

 
5,313

General and administrative expenses
 
649

 
579

 
70

Depreciation and amortization expense
 
24,586

 
27,150

 
(2,564
)
Loss on disposal or impairment of assets, net
 
2,929

 
2,323

 
606

Total expenses
 
65,397

 
52,257

 
13,140

Segment operating loss
 
$
(1,373
)
 
$
(11,898
)
 
$
10,525

 
 
 
 
 
 
 
Wastewater processed (barrels per day)
 
 
 
 
 
 
Eagle Ford Basin
 
255,634

 
203,349

 
52,285

Permian Basin
 
334,556

 
208,495

 
126,061

DJ Basin
 
121,061

 
67,560

 
53,501

Other Basins
 
78,144

 
36,778

 
41,366

Total
 
789,395

 
516,182

 
273,213

Solids processed (barrels per day)
 
6,095

 
2,624

 
3,471

Skim oil sold (barrels per day)
 
3,623

 
1,597

 
2,026

Service fees for wastewater processed ($/barrel)
 
$
0.57

 
$
0.60

 
$
(0.03
)
Recovered hydrocarbons for wastewater processed ($/barrel)
 
$
0.23

 
$
0.13

 
$
0.10

Operating expenses for wastewater processed ($/barrel)
 
$
0.37

 
$
0.46

 
$
(0.09
)

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

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

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

Cost of Sales-Derivatives . We enter into derivatives in our Water Solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expect to recover when processing the wastewater and selling the skim oil. Our cost of sales during the three months ended December 31, 2017 included $8.5 million of net unrealized losses on derivatives and $1.0 million of net realized losses on derivatives. Our cost of sales during the three months ended December 31, 2016 included $1.3 million of net unrealized gains on derivatives and $1.1 million of net realized losses on derivatives.

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


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

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

Loss on Disposal or Impairment of Assets, Net . During the three months ended December 31, 2017 , we recorded a net loss of $2.9 million on the disposals of certain assets. During the three months ended December 31, 2016 , we recorded a net loss of $2.3 million on the sale of Grassland and the sales of certain other assets.


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Liquids

The following table summarizes the operating results of our Liquids segment for the periods indicated:
 
 
Three Months Ended December 31,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per gallon amounts)
Propane sales:
 
 
 
 
 
 
Revenues (1)
 
$
403,236

 
$
260,562

 
$
142,674

Cost of sales
 
388,861

 
242,949

 
145,912

Product margin
 
14,375

 
17,613

 
(3,238
)
 
 
 
 
 
 
 
Butane sales:
 
 
 
 
 
 
Revenues (1)
 
228,535

 
146,514

 
82,021

Cost of sales
 
215,588

 
135,246

 
80,342

Product margin
 
12,947

 
11,268

 
1,679

 
 
 
 
 
 
 
Other product sales:
 
 
 
 
 
 
Revenues (1)
 
123,677

 
89,225

 
34,452

Cost of sales
 
118,050

 
84,071

 
33,979

Product margin
 
5,627

 
5,154

 
473

 
 
 
 
 
 
 
Other revenues:
 
 
 
 
 
 
Revenues (1)
 
6,166

 
7,704

 
(1,538
)
Cost of sales
 
772

 
2,410

 
(1,638
)
Product margin
 
5,394

 
5,294

 
100

 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
8,659

 
8,846

 
(187
)
General and administrative expenses
 
1,361

 
1,217

 
144

Depreciation and amortization expense
 
6,247

 
4,441

 
1,806

(Gain) loss on disposal or impairment of assets, net
 
(214
)
 
60

 
(274
)
Total expenses
 
16,053

 
14,564

 
1,489

Segment operating income
 
$
22,290

 
$
24,765

 
$
(2,475
)
 
 
 
 
 
 
 
Liquids storage capacity - owned and leased (gallons) (2)
 
453,971

 
358,537

 
95,434

 
 
 
 
 
 
 
Propane sold (gallons)
 
399,211

 
386,854

 
12,357

Propane sold ($/gallon)
 
$
1.010

 
$
0.674

 
$
0.336

Cost per propane sold ($/gallon)
 
$
0.974

 
$
0.628

 
$
0.346

Propane product margin ($/gallon)
 
$
0.036

 
$
0.046

 
$
(0.010
)
Propane inventory (gallons) (2)
 
130,940

 
135,582

 
(4,642
)
Propane storage capacity leased to third parties (gallons) (2)
 
33,495

 
33,264

 
231

 
 
 
 
 
 
 
Butane sold (gallons)
 
191,504

 
149,403

 
42,101

Butane sold ($/gallon)
 
$
1.193

 
$
0.981

 
$
0.212

Cost per butane sold ($/gallon)
 
$
1.126

 
$
0.905

 
$
0.221

Butane product margin ($/gallon)
 
$
0.067

 
$
0.076

 
$
(0.009
)
Butane inventory (gallons) (2)
 
41,941

 
22,261

 
19,680

Butane storage capacity leased to third parties (gallons) (2)
 
80,346

 
72,540

 
7,806

 
 
 
 
 
 
 
Other products sold (gallons)
 
104,136

 
89,974

 
14,162

Other products sold ($/gallon)
 
$
1.188

 
$
0.992

 
$
0.196

Cost per other products sold ($/gallon)
 
$
1.134

 
$
0.934

 
$
0.200

Other products product margin ($/gallon)
 
$
0.054

 
$
0.058

 
$
(0.004
)
Other products inventory (gallons) (2)
 
9,616

 
6,887

 
2,729

 
(1)
Revenues include $52.6 million and $33.7 million of intersegment sales during the three months ended December 31, 2017 and 2016 , respectively, that are eliminated in our unaudited condensed consolidated statements of operations.
(2)
Information is presented as of December 31, 2017 and December 31, 2016 , respectively.

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

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

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

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

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

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

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

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

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

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

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

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

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


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Retail Propane

The following table summarizes the operating results of our Retail Propane segment for the periods indicated:
 
 
Three Months Ended December 31,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per gallon amounts)
Propane sales:
 
 
 
 
 
 
Revenues (1)
 
$
124,466

 
$
96,699

 
$
27,767

Cost of sales
 
66,368

 
42,463

 
23,905

Product margin
 
58,098

 
54,236

 
3,862

 
 
 
 
 
 
 
Distillate sales:
 
 
 
 
 
 
Revenues (1)
 
22,806

 
19,569

 
3,237

Cost of sales
 
17,336

 
14,300

 
3,036

Product margin
 
5,470

 
5,269

 
201

 
 
 
 
 
 
 
Other revenues:
 
 
 
 
 
 
Revenues (1)
 
12,797

 
12,418

 
379

Cost of sales
 
3,783

 
3,745

 
38

Product margin
 
9,014

 
8,673

 
341

 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
33,750

 
32,279

 
1,471

General and administrative expenses
 
2,822

 
2,810

 
12

Depreciation and amortization expense
 
11,130

 
11,379

 
(249
)
Loss (gain) on disposal or impairment of assets, net
 
908

 
(62
)
 
970

Total expenses
 
48,610

 
46,406

 
2,204

Segment operating income
 
$
23,972

 
$
21,772

 
$
2,200

 
 
 
 
 
 
 
Propane sold (gallons)
 
62,058

 
56,572

 
5,486

Propane sold ($/gallon)
 
$
2.006

 
$
1.709

 
$
0.297

Cost per propane sold ($/gallon)
 
$
1.069

 
$
0.751

 
$
0.318

Propane product margin ($/gallon)
 
$
0.937

 
$
0.958

 
$
(0.021
)
Propane inventory (gallons) (2)
 
6,760

 
10,708

 
(3,948
)
 
 
 
 
 
 
 
Distillates sold (gallons)
 
9,381

 
9,139

 
242

Distillates sold ($/gallon)
 
$
2.431

 
$
2.141

 
$
0.290

Cost per distillates sold ($/gallon)
 
$
1.848

 
$
1.565

 
$
0.283

Distillates product margin ($/gallon)
 
$
0.583

 
$
0.576

 
$
0.007

Distillates inventory (gallons) (2)
 
2,618

 
2,457

 
161

 
(1)
Revenues include less than $0.1 million of intersegment sales during the three months ended December 31, 2017 that are eliminated in our unaudited condensed consolidated statements of operations.
(2)
Information is presented as of December 31, 2017 and December 31, 2016 , respectively, and does not include the inventory for the portion of the Retail Propane segment that has been classified as held for sale as of December 31, 2017 (see Note 14 to our unaudited condensed consolidated financial statements included in this Quarterly Report).

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


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

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

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

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


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Refined Products and Renewables

The following table summarizes the operating results of our Refined Products and Renewables segment for the periods indicated:
 
 
Three Months Ended December 31,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per barrel amounts)
Refined products sales:
 
 
 
 
 
 
Revenues (1)
 
$
2,845,482

 
$
2,258,317

 
$
587,165

Cost of sales
 
2,862,533

 
2,254,283

 
608,250

Product (loss) margin
 
(17,051
)
 
4,034

 
(21,085
)
 
 
 
 
 
 
 
Renewables sales:
 
 
 
 
 
 
Revenues
 
99,436

 
123,065

 
(23,629
)
Cost of sales
 
89,045

 
120,041

 
(30,996
)
Product margin
 
10,391

 
3,024

 
7,367

 
 
 
 
 
 
 
Service fee revenues
 
94

 
50

 
44

 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
3,343

 
3,198

 
145

General and administrative expenses
 
2,088

 
2,238

 
(150
)
Depreciation and amortization expense
 
323

 
404

 
(81
)
Gain on disposal or impairment of assets, net
 
(7,529
)
 
(6,941
)
 
(588
)
Total income
 
(1,775
)
 
(1,101
)
 
(674
)
Segment operating (loss) income
 
$
(4,791
)
 
$
8,209

 
$
(13,000
)
 
 
 
 
 
 
 
Gasoline sold (barrels)
 
22,902

 
22,227

 
675

Diesel sold (barrels)
 
15,004

 
13,215

 
1,789

Ethanol sold (barrels)
 
900

 
1,125

 
(225
)
Biodiesel sold (barrels)
 
477

 
733

 
(256
)
Refined products and renewables storage capacity - leased (barrels) (2)
 
9,046

 
7,794

 
1,252

Refined products and renewables storage capacity sub-leased to third parties (barrels) (2)
 
1,068

 
938

 
130

Gasoline inventory (barrels) (2)
 
3,007

 
2,627

 
380

Diesel inventory (barrels) (2)
 
1,605

 
2,738

 
(1,133
)
Ethanol inventory (barrels) (2)
 
684

 
502

 
182

Biodiesel inventory (barrels) (2)
 
153

 
501

 
(348
)
Refined products sold ($/barrel)
 
$
75.067

 
$
63.719

 
$
11.348

Cost per refined products sold ($/barrel)
 
$
75.517

 
$
63.605

 
$
11.912

Refined products product (loss) margin ($/barrel)
 
$
(0.450
)
 
$
0.114

 
$
(0.564
)
Renewable products sold ($/barrel)
 
$
72.212

 
$
66.235

 
$
5.977

Cost per renewable products sold ($/barrel)
 
$
64.666

 
$
64.608

 
$
0.058

Renewable products product margin ($/barrel)
 
$
7.546

 
$
1.627

 
$
5.919

 
(1)
Revenues include $0.1 million and $0.1 million of intersegment sales during the three months ended December 31, 2017 and 2016 , respectively, that are eliminated in our unaudited condensed consolidated statements of operations.
(2)
Information is presented as of December 31, 2017 and December 31, 2016 , respectively.

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

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

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

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

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

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

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

$7.5 million of the deferred gain from the sale of the general partner interest in TLP (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion) ; and
a loss of $0.6 million on the sales of certain assets.

Corporate and Other

The operating loss within “Corporate and Other” includes the following components for the periods indicated:
 
 
Three Months Ended December 31,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands)
Other revenues
 
 
 
 
 
 
Revenues
 
$
289

 
$
164

 
$
125

Cost of sales
 
117

 
77

 
40

Margin
 
172

 
87

 
85

 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
385

 
371

 
14

General and administrative expenses
 
20,671

 
9,955

 
10,716

Depreciation and amortization expense
 
962

 
890

 
72

Gain on disposal or impairment of assets, net
 

 
(1
)
 
1

Total expenses
 
22,018

 
11,215

 
10,803

Operating loss
 
$
(21,846
)
 
$
(11,128
)
 
$
(10,718
)

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

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Equity in Earnings of Unconsolidated Entities

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

Interest Expense

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

Loss on Early Extinguishment of Liabilities, Net

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

Other Income, Net

The following table summarizes the components of other income, net for the periods indicated:
 
Three Months Ended December 31,
 
2017
 
2016
 
(in thousands)
Interest income (1)
$
1,787

 
$
1,921

Crude oil marketing arrangement (2)
(38
)
 
39

Termination of storage sublease agreement (3)

 
16,205

Other (4)
358

 
1,842

Other income, net
$
2,107

 
$
20,007

 
(1)
Relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party and to a loan receivable from an equity method investee (see Note 2 and Note 13 , respectively, to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion).
(2)
Represents another party’s share of the profits and losses generated from a joint crude oil marketing arrangement.
(3)
During the three months ended December 31, 2016, we agreed to terminate a storage sublease agreement that was scheduled to commence in January 2017 and had a term of five years. For terminating this agreement, the counterparty agreed to pay us a specific amount in five equal payments beginning in February 2017 and in January of the next four years and removed any future obligations of the Partnership. As a result, we discounted the future payments and recorded a gain.
(4)
During the three months ended December 31, 2017 , this relates primarily to proceeds from a litigation settlement. During the three months ended December 31, 2016, this relates primarily to a gain on insurance settlement from damage to two facilities in our Water Solutions segment and a payment received related to a contract termination.

Income Tax Expense

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

 

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

Crude Oil Logistics

The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated:
 
 
Nine Months Ended December 31,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per barrel amounts)
Revenues:
 
 
 
 
 
 
Crude oil sales
 
$
1,446,560

 
$
1,123,169

 
$
323,391

Crude oil transportation and other
 
89,318

 
43,020

 
46,298

Total revenues (1)
 
1,535,878

 
1,166,189

 
369,689

Expenses:
 
 

 
 

 
 

Cost of sales
 
1,432,445

 
1,112,034

 
320,411

Operating expenses
 
36,079

 
29,413

 
6,666

General and administrative expenses
 
4,927

 
4,456

 
471

Depreciation and amortization expense
 
61,885

 
34,496

 
27,389

(Gain) loss on disposal or impairment of assets, net
 
(111,290
)
 
14,617

 
(125,907
)
Total expenses
 
1,424,046

 
1,195,016

 
229,030

Segment operating income (loss)
 
$
111,832

 
$
(28,827
)
 
$
140,659

 
 
 
 
 
 
 
Crude oil sold (barrels)
 
28,588

 
24,838

 
3,750

Crude oil transported on owned pipelines (barrels)
 
24,176

 
1,610

 
22,566

Crude oil storage capacity - owned and leased (barrels) (2)
 
6,362

 
6,765

 
(403
)
Crude oil storage capacity leased to third parties (barrels) (2)
 
2,829

 
4,398

 
(1,569
)
Crude oil inventory (barrels) (2)
 
1,356

 
2,037

 
(681
)
Crude oil sold ($/barrel)
 
$
50.600

 
$
45.220

 
$
5.380

Cost per crude oil sold ($/barrel)
 
$
50.107

 
$
44.771

 
$
5.336

Crude oil product margin ($/barrel)
 
$
0.493

 
$
0.449

 
$
0.044

 
(1)
Revenues include $8.9 million and $4.4 million of intersegment sales during the nine months ended December 31, 2017 and 2016 , respectively, that are eliminated in our unaudited condensed consolidated statements of operations.
(2)
Information is presented as of December 31, 2017 and December 31, 2016 , respectively.

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

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

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

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

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

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

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


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Water Solutions

The following table summarizes the operating results of our Water Solutions segment for the periods indicated:
 
 
Nine Months Ended December 31,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per barrel and per day amounts)
Revenues:
 
 
 
 
 
 
Service fees
 
$
109,648

 
$
82,493

 
$
27,155

Recovered hydrocarbons
 
37,427

 
19,264

 
18,163

Other revenues
 
14,948

 
14,088

 
860

Total revenues
 
162,023

 
115,845

 
46,178

Expenses:
 
 
 
 
 
 
Cost of sales-derivative loss
 
11,529

 
2,449

 
9,080

Cost of sales-other
 
1,490

 
1,422

 
68

Operating expenses
 
74,570

 
62,233

 
12,337

General and administrative expenses
 
1,948

 
1,850

 
98

Depreciation and amortization expense
 
73,847

 
76,713

 
(2,866
)
Loss (gain) on disposal or impairment of assets, net
 
3,114

 
(91,958
)
 
95,072

Revaluation of liabilities
 
5,600

 

 
5,600

Total expenses
 
172,098

 
52,709

 
119,389

Segment operating (loss) income
 
$
(10,075
)
 
$
63,136

 
$
(73,211
)
 
 
 
 
 
 
 
Wastewater processed (barrels per day)
 
 
 
 
 
 
Eagle Ford Basin
 
228,698

 
207,732

 
20,966

Permian Basin
 
280,158

 
182,165

 
97,993

DJ Basin
 
114,156

 
62,495

 
51,661

Other Basins
 
66,884

 
38,199

 
28,685

Total
 
689,896

 
490,591

 
199,305

Solids processed (barrels per day)
 
5,357

 
2,643

 
2,714

Skim oil sold (barrels per day)
 
2,923

 
1,714

 
1,209

Service fees for wastewater processed ($/barrel)
 
$
0.58

 
$
0.61

 
$
(0.03
)
Recovered hydrocarbons for wastewater processed ($/barrel)
 
$
0.20

 
$
0.14

 
$
0.06

Operating expenses for wastewater processed ($/barrel)
 
$
0.39

 
$
0.46

 
$
(0.07
)

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

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

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

Cost of Sales-Derivatives . We enter into derivatives in our Water Solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expect to recover when processing the wastewater and selling the skim oil. Our cost of sales during the nine months ended December 31, 2017 included $11.5 million of net unrealized losses on derivatives and less than $0.1 million of net realized losses on derivatives. Our cost of sales during the nine months ended December 31, 2016 included $4.6 million of net realized losses on derivatives and $2.1 million of net unrealized gains on derivatives.

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

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

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

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

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

an adjustment of $124.7 million of the previously recorded $380.2 million estimated goodwill impairment charge recorded during the three months ended March 31, 2016;
a write-off of $5.2 million related to the value of an indefinite-lived trade name intangible asset in conjunction with finalizing our goodwill impairment analysis in June 2016;
a loss of $22.7 million related to the termination of a development agreement in June 2016, which included the carrying value of the development agreement asset that was written off;
a net loss of $3.1 million on the sale of Grassland and the sales of certain other assets; and
an impairment charge of $1.7 million to write down a loan receivable in June 2016.

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


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Liquids

The following table summarizes the operating results of our Liquids segment for the periods indicated:
 
 
Nine Months Ended December 31,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per gallon amounts)
Propane sales:
 
 
 
 
 
 
Revenues (1)
 
$
733,684

 
$
458,646

 
$
275,038

Cost of sales
 
703,135

 
430,775

 
272,360

Product margin
 
30,549

 
27,871

 
2,678

 
 
 
 
 
 
 
Butane sales:
 
 
 
 
 
 
Revenues (1)
 
408,312

 
267,769

 
140,543

Cost of sales
 
406,835

 
248,082

 
158,753

Product margin
 
1,477

 
19,687

 
(18,210
)
 
 
 
 
 
 
 
Other product sales:
 
 
 
 
 
 
Revenues (1)
 
310,389

 
217,405

 
92,984

Cost of sales
 
295,590

 
201,457

 
94,133

Product margin
 
14,799

 
15,948

 
(1,149
)
 
 
 
 
 
 
 
Other revenues:
 
 
 
 
 
 
Revenues (1)
 
16,106

 
22,926

 
(6,820
)
Cost of sales
 
2,294

 
8,069

 
(5,775
)
Product margin
 
13,812

 
14,857

 
(1,045
)
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
25,011

 
28,386

 
(3,375
)
General and administrative expenses
 
3,982

 
3,461

 
521

Depreciation and amortization expense
 
18,718

 
13,315

 
5,403

Loss on disposal or impairment of assets, net
 
117,515

 
109

 
117,406

Total expenses
 
165,226

 
45,271

 
119,955

Segment operating (loss) income
 
$
(104,589
)
 
$
33,092

 
$
(137,681
)
 
 
 
 
 
 
 
Liquids storage capacity - owned and leased (gallons) (2)
 
453,971

 
358,537

 
95,434

 
 
 
 
 
 
 
Propane sold (gallons)
 
881,719

 
813,490

 
68,229

Propane sold ($/gallon)
 
$
0.832

 
$
0.564

 
$
0.268

Cost per propane sold ($/gallon)
 
$
0.797

 
$
0.530

 
$
0.267

Propane product margin ($/gallon)
 
$
0.035

 
$
0.034

 
$
0.001

Propane inventory (gallons) (2)
 
130,940

 
135,582

 
(4,642
)
Propane storage capacity leased to third parties (gallons) (2)
 
33,495

 
33,264

 
231

 
 
 
 
 
 
 
Butane sold (gallons)
 
408,440

 
347,858

 
60,582

Butane sold ($/gallon)
 
$
1.000

 
$
0.770

 
$
0.230

Cost per butane sold ($/gallon)
 
$
0.996

 
$
0.713

 
$
0.283

Butane product margin ($/gallon)
 
$
0.004

 
$
0.057

 
$
(0.053
)
Butane inventory (gallons) (2)
 
41,941

 
22,261

 
19,680

Butane storage capacity leased to third parties (gallons) (2)
 
80,346

 
72,540

 
7,806

 
 
 
 
 
 
 
Other products sold (gallons)
 
296,756

 
256,451

 
40,305

Other products sold ($/gallon)
 
$
1.046

 
$
0.848

 
$
0.198

Cost per other products sold ($/gallon)
 
$
0.996

 
$
0.786

 
$
0.210

Other products product margin ($/gallon)
 
$
0.050

 
$
0.062

 
$
(0.012
)
Other products inventory (gallons) (2)
 
9,616

 
6,887

 
2,729

 
(1)
Revenues include $88.5 million and $57.2 million of intersegment sales during the nine months ended December 31, 2017 and 2016 , respectively, that are eliminated in our unaudited condensed consolidated statements of operations.
(2)
Information is presented as of December 31, 2017 and December 31, 2016 , respectively.

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

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

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

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

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

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

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

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

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

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

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

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

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


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Retail Propane

The following table summarizes the operating results of our Retail Propane segment for the periods indicated:
 
 
Nine Months Ended December 31,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per gallon amounts)
Propane sales:
 
 
 
 
 
 
Revenues (1)
 
$
221,102

 
$
174,510

 
$
46,592

Cost of sales
 
108,706

 
70,564

 
38,142

Product margin
 
112,396

 
103,946

 
8,450

 
 
 
 
 
 
 
Distillate sales:
 
 
 
 
 
 
Revenues (1)
 
39,037

 
35,613

 
3,424

Cost of sales
 
29,741

 
26,244

 
3,497

Product margin
 
9,296

 
9,369

 
(73
)
 
 
 
 
 
 
 
Other revenues:
 
 
 
 
 
 
Revenues (1)
 
31,733

 
30,056

 
1,677

Cost of sales
 
9,996

 
9,211

 
785

Product margin
 
21,737

 
20,845

 
892

 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
90,592

 
84,628

 
5,964

General and administrative expenses
 
7,750

 
7,304

 
446

Depreciation and amortization expense
 
34,205

 
31,771

 
2,434

Loss (gain) on disposal or impairment of assets, net
 
2,004

 
(96
)
 
2,100

Total expenses
 
134,551

 
123,607

 
10,944

Segment operating income
 
$
8,878

 
$
10,553

 
$
(1,675
)
 
 
 
 
 
 
 
Propane sold (gallons)
 
117,488

 
105,933

 
11,555

Propane sold ($/gallon)
 
$
1.882

 
$
1.647

 
$
0.235

Cost per propane sold ($/gallon)
 
$
0.925

 
$
0.666

 
$
0.259

Propane product margin ($/gallon)
 
$
0.957

 
$
0.981

 
$
(0.024
)
Propane inventory (gallons) (2)
 
6,760

 
10,708

 
(3,948
)
 
 
 
 
 
 
 
Distillates sold (gallons)
 
17,088

 
17,505

 
(417
)
Distillates sold ($/gallon)
 
$
2.284

 
$
2.034

 
$
0.250

Cost per distillates sold ($/gallon)
 
$
1.740

 
$
1.499

 
$
0.241

Distillates product margin ($/gallon)
 
$
0.544

 
$
0.535

 
$
0.009

Distillates inventory (gallons) (2)
 
2,618

 
2,457

 
161

 
(1)
Revenues include $0.1 million and less than $0.1 million of intersegment sales during the nine months ended December 31, 2017 and 2016 , respectively, that are eliminated in our unaudited condensed consolidated statement of operations.
(2)
Information is presented as of December 31, 2017 and December 31, 2016 , respectively, and does not include the inventory for the portion of the Retail Propane segment that has been classified as held for sale as of December 31, 2017 (see Note 14 to our unaudited condensed consolidated financial statements included in this Quarterly Report).

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


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

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

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

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


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Refined Products and Renewables

The following table summarizes the operating results of our Refined Products and Renewables segment for the periods indicated:
 
 
Nine Months Ended December 31,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per barrel amounts)
Refined products sales:
 
 
 
 
 
 
Revenues (1)
 
$
8,493,357

 
$
6,409,889

 
$
2,083,468

Cost of sales
 
8,478,512

 
6,353,792

 
2,124,720

Product margin
 
14,845

 
56,097

 
(41,252
)
 
 
 
 
 
 
 
Renewables sales:
 
 
 
 
 
 
Revenues
 
313,366

 
325,377

 
(12,011
)
Cost of sales
 
302,765

 
320,695

 
(17,930
)
Product margin
 
10,601

 
4,682

 
5,919

 
 
 
 
 
 
 
Service fee revenues
 
262

 
11,195

 
(10,933
)
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
10,232

 
19,861

 
(9,629
)
General and administrative expenses
 
6,343

 
7,612

 
(1,269
)
Depreciation and amortization expense
 
971

 
1,237

 
(266
)
Gain on disposal or impairment of assets, net
 
(22,585
)
 
(126,101
)
 
103,516

Total income
 
(5,039
)
 
(97,391
)
 
92,352

Segment operating income
 
$
30,747

 
$
169,365

 
$
(138,618
)
 
 
 
 
 
 
 
Gasoline sold (barrels)
 
77,877

 
65,278

 
12,599

Diesel sold (barrels)
 
43,792

 
38,415

 
5,377

Ethanol sold (barrels)
 
2,892

 
3,190

 
(298
)
Biodiesel sold (barrels)
 
1,672

 
1,948

 
(276
)
Refined products and renewables storage capacity - leased (barrels) (2)
 
9,046

 
7,794

 
1,252

Refined products and renewables storage capacity sub-leased to third parties (barrels) (2)
 
1,068

 
938

 
130

Gasoline inventory (barrels) (2)
 
3,007

 
2,627

 
380

Diesel inventory (barrels) (2)
 
1,605

 
2,738

 
(1,133
)
Ethanol inventory (barrels) (2)
 
684

 
502

 
182

Biodiesel inventory (barrels) (2)
 
153

 
501

 
(348
)
Refined products sold ($/barrel)
 
$
69.807

 
$
61.816

 
$
7.991

Cost per refined products sold ($/barrel)
 
$
69.685

 
$
61.275

 
$
8.410

Refined products product margin ($/barrel)
 
$
0.122

 
$
0.541

 
$
(0.419
)
Renewable products sold ($/barrel)
 
$
68.660

 
$
63.328

 
$
5.332

Cost per renewable products sold ($/barrel)
 
$
66.338

 
$
62.416

 
$
3.922

Renewable products product margin ($/barrel)
 
$
2.322

 
$
0.912

 
$
1.410

 
(1)
Revenues include $0.3 million and $0.3 million of intersegment sales during the nine months ended December 31, 2017 and 2016 , respectively, that are eliminated in our unaudited condensed consolidated statements of operations.
(2)
Information is presented as of December 31, 2017 and December 31, 2016 , respectively.

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

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

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

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

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

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

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

a $104.1 million gain from the sale of all of the TLP units we owned;
$22.6 million of the deferred gain from the sale of the general partner interest in TLP (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion) ; and
a loss of $0.6 million on the sales of certain assets.

Corporate and Other

The operating loss within “Corporate and Other” includes the following components for the periods indicated:
 
 
Nine Months Ended December 31,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands)
Other revenues
 
 
 
 
 
 
Revenues
 
$
696

 
$
679

 
$
17

Cost of sales
 
311

 
300

 
11

Margin
 
385

 
379

 
6

 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
876

 
935

 
(59
)
General and administrative expenses
 
52,739

 
63,394

 
(10,655
)
Depreciation and amortization expense
 
2,801

 
2,744

 
57

Gain on disposal or impairment of assets, net
 

 
(4
)
 
4

Total expenses
 
56,416

 
67,069

 
(10,653
)
Operating loss
 
$
(56,031
)
 
$
(66,690
)
 
$
10,659


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

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

 
Equity in Earnings of Unconsolidated Entities

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

Revaluation of Investments

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

Interest Expense

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

(Loss) Gain on Early Extinguishment of Liabilities, Net

The following table summarizes the components of (loss) gain on early extinguishment of liabilities, net for the periods indicated:
 
Nine Months Ended December 31,
 
2017
 
2016
 
(in thousands)
Early extinguishment of long-term debt (1)
$
(22,479
)
 
$
8,614

Release of contingent consideration liabilities (2)

 
22,276

(Loss) gain on early extinguishment of liabilities, net
$
(22,479
)
 
$
30,890

 
(1)
During the nine months ended December 31, 2017 , this relates to net losses on the early extinguishment of all of the senior secured notes and a portion of the 5.125% senior notes due 2019 (“2019 Notes”), 2023 Notes and 2025 Notes. During the nine months ended December 31, 2016 , this relates to gains on the early extinguishment of a portion of the 2019 Notes and 6.875% senior notes due 2021 (“2021 Notes”). See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.
(2)
Relates to the release of certain contingent consideration liabilities in conjunction with the termination of a development agreement in June 2016. Also, during the nine months ended December 31, 2016 , we acquired certain parcels of land on which one of our water solutions facilities is located and recorded a gain on the release of certain contingent consideration liabilities as the royalty agreement was terminated.


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Other Income, Net

The following table summarizes the components of other income, net for the periods indicated:
 
Nine Months Ended December 31,
 
2017
 
2016
 
(in thousands)
Interest income (1)
$
5,745

 
$
6,341

Crude oil marketing arrangement (2)
(48
)
 
(1,512
)
Termination of storage sublease agreement (3)

 
16,205

Other (4)
416

 
4,826

Other income, net
$
6,113

 
$
25,860

 
(1)
Relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party and to a loan receivable from an equity method investee (see Note 2 and Note 13 , respectively, to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion). As previously reported, on June 3, 2016, we acquired the remaining 65% ownership interest in Grassland and all interest income on that receivable has been eliminated in consolidation subsequent to that date.
(2)
Represents another party’s share of the profits and losses generated from a joint crude oil marketing arrangement.
(3)
During the nine months ended December 31, 2016 , we agreed to terminate a storage sublease agreement that was scheduled to commence in January 2017 and had a term of five years. For terminating this agreement, the counterparty agreed to pay us a specific amount in five equal payments beginning in February 2017 and in January of the next four years and removed any future obligations of the Partnership. As a result, we discounted the future payments and recorded a gain.
(4)
During the nine months ended December 31, 2017 , this relates primarily to proceeds from a litigation settlement. During the nine months ended December 31, 2016 , this relates primarily to a distribution from TLP pursuant to the agreement to sell all of the TLP common units we owned in April 2016, a gain on insurance settlement from damage to two facilities in our Water Solutions segment and a payment received related to a contract termination.

Income Tax Expense

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

Noncontrolling Interests - Redeemable and Non-redeemable

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

Non-GAAP Financial Measures

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

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

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activities, or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information to investors for evaluating our ability to make quarterly distributions to our unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information to investors for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA, Adjusted EBITDA, or similarly titled measures used by other entities.

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

The following table reconciles net income (loss) to EBITDA and Adjusted EBITDA:
 
Three Months Ended December 31,
 
Nine Months Ended December 31,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Net income (loss)
$
56,769

 
$
1,293

 
$
(180,517
)
 
$
117,388

Less: Net income attributable to noncontrolling interests
(89
)
 
(317
)
 
(221
)
 
(6,091
)
Less: Net (income) loss attributable to redeemable noncontrolling interests
(424
)
 

 
261

 

Net income (loss) attributable to NGL Energy Partners LP
56,256

 
976

 
(180,477
)
 
111,297

Interest expense
51,825

 
41,486

 
151,391

 
105,283

Income tax expense
364

 
1,114

 
934

 
2,036

Depreciation and amortization
67,025

 
64,644

 
204,514

 
171,746

EBITDA
175,470

 
108,220

 
176,362

 
390,362

Net unrealized losses (gains) on derivatives
775

 
(3,957
)
 
16,851

 
(737
)
Inventory valuation adjustment (1)
27,786

 
7,859

 
6,439

 
40,552

Lower of cost or market adjustments
(3,907
)
 
731

 
5,504

 
839

(Gain) loss on disposal or impairment of assets, net
(111,479
)
 
35

 
(11,241
)
 
(203,469
)
Loss (gain) on early extinguishment of liabilities, net
21,141

 

 
22,479

 
(30,890
)
Revaluation of investments

 

 

 
14,365

Equity-based compensation expense (2)
12,228

 
6,865

 
27,114

 
39,859

Acquisition expense (3)
186

 
378

 
132

 
1,539

Revaluation of liabilities

 

 
5,600

 

Other (4)
448

 
617

 
3,089

 
7,734

Adjusted EBITDA
$
122,648

 
$
120,748

 
$
252,329

 
$
260,154

 
(1)
Amount reflects the difference between the market value of the inventory of our Refined Products and Renewables segment at the balance sheet date and its cost. See “Non-GAAP Financial Measures” section above for a further discussion.
(2)
Equity-based compensation expense in the table above may differ from equity-based compensation expense reported in Note 10 to our unaudited condensed consolidated financial statements included in this Quarterly Report. Amounts reported in the table above include expense accruals for bonuses expected to be paid in common units, whereas the amounts reported in Note 10 to our unaudited condensed consolidated financial statements only include expenses associated with equity-based awards that have been formally granted.
(3)
Amounts represent expenses we incurred related to legal and advisory costs associated with acquisitions, partially offset by reimbursement for certain legal costs incurred in prior periods.

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(4)
Amounts for the three months ended December 31, 2017 and 2016 and the nine months ended December 31, 2017 represent non-cash operating expenses related to our Grand Mesa Pipeline and accretion expense for asset retirement obligations. The amount for the nine months ended December 31, 2016 represents non-cash operating expenses related to our Grand Mesa Pipeline, adjustments related to noncontrolling interests and accretion expense for asset retirement obligations.

The following tables reconcile depreciation and amortization amounts per the EBITDA table above to depreciation and amortization amounts reported in our unaudited condensed consolidated statements of operations and unaudited condensed consolidated statements of cash flows for the periods indicated:
 
 
Three Months Ended December 31,
 
Nine Months Ended December 31,
 
 
2017
 
2016
 
2017
 
2016
 
 
(in thousands)
Reconciliation to unaudited condensed consolidated statements of operations:
 
 
 
 
 
 
 
 
Depreciation and amortization per EBITDA table
 
$
67,025

 
$
64,644

 
$
204,514

 
$
171,746

Intangible asset amortization recorded to cost of sales
 
(1,505
)
 
(1,753
)
 
(4,596
)
 
(5,098
)
Depreciation and amortization of unconsolidated entities
 
(2,483
)
 
(3,048
)
 
(8,511
)
 
(9,116
)
Depreciation and amortization attributable to noncontrolling interests
 
303

 
924

 
1,020

 
2,744

Depreciation and amortization per unaudited condensed consolidated statements of operations
 
$
63,340

 
$
60,767

 
$
192,427

 
$
160,276


 
 
Nine Months Ended December 31,
 
 
2017
 
2016
 
 
(in thousands)
Reconciliation to unaudited condensed consolidated statements of cash flows:
 
 
 
 
Depreciation and amortization per EBITDA table
 
$
204,514

 
$
171,746

Amortization of debt issuance costs recorded to interest expense
 
8,169

 
8,192

Depreciation and amortization of unconsolidated entities
 
(8,511
)
 
(9,116
)
Depreciation and amortization attributable to noncontrolling interests
 
1,020

 
2,744

Depreciation and amortization per unaudited condensed consolidated statements of cash flows
 
$
205,192

 
$
173,566


The following table reconciles interest expense per the EBITDA table above to interest expense reported in our unaudited condensed consolidated statements of operations for the periods indicated:
 
 
Three Months Ended December 31,
 
Nine Months Ended December 31,
 
 
2017
 
2016
 
2017
 
2016
 
 
(in thousands)
Interest expense per EBITDA table
 
$
51,825

 
$
41,486

 
$
151,391

 
$
105,283

Interest expense attributable to noncontrolling interests
 
7

 
9

 
25

 
17

Interest expense attributable to unconsolidated entities
 
(42
)
 
(59
)
 
(167
)
 
16

Interest expense per unaudited condensed consolidated statements of operations
 
$
51,790

 
$
41,436

 
$
151,249

 
$
105,316



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The following tables reconcile operating income (loss) to Adjusted EBITDA by segment for the periods indicated. We have revised certain prior period information to be consistent with the calculation method used in the current fiscal year.
 
 
Three Months Ended December 31, 2017
 
 
Crude Oil
Logistics
 
Water
Solutions
 
Liquids
 
Retail
Propane
 
Refined
Products
and
Renewables
 
Corporate
and
Other
 
Consolidated
 
 
(in thousands)
Operating income (loss)
 
$
106,279

 
$
(1,373
)
 
$
22,290

 
$
23,972

 
$
(4,791
)
 
$
(21,846
)
 
$
124,531

Depreciation and amortization
 
20,092

 
24,586

 
6,247

 
11,130

 
323

 
962

 
63,340

Amortization recorded to cost of sales
 
85

 

 
70

 

 
1,350

 

 
1,505

Net unrealized losses (gains) on derivatives
 
962

 
8,504

 
(8,550
)
 
(141
)
 

 

 
775

Inventory valuation adjustment
 

 

 

 

 
27,786

 

 
27,786

Lower of cost or market adjustments
 
5,207

 

 

 

 
(9,114
)
 

 
(3,907
)
(Gain) loss on disposal or impairment of assets, net
 
(107,574
)
 
2,929

 
(214
)
 
908

 
(7,529
)
 

 
(111,480
)
Equity-based compensation expense
 

 

 

 

 

 
12,228

 
12,228

Acquisition expense
 

 

 

 

 

 
186

 
186

Other income, net
 
5

 
190

 
93

 
29

 
151

 
1,639

 
2,107

Adjusted EBITDA attributable to unconsolidated entities
 
3,887

 
144

 

 
902

 
1,018

 

 
5,951

Adjusted EBITDA attributable to noncontrolling interest
 

 
(185
)
 

 
(637
)
 

 

 
(822
)
Other
 
1,377

 
91

 
21

 
(1,041
)
 

 

 
448

Adjusted EBITDA
 
$
30,320

 
$
34,886

 
$
19,957

 
$
35,122

 
$
9,194

 
$
(6,831
)
 
$
122,648

 
 
Three Months Ended December 31, 2016
 
 
Crude Oil
Logistics
 
Water
Solutions
 
Liquids
 
Retail
Propane
 
Refined
Products
and
Renewables
 
Corporate
and
Other
 
Consolidated
 
 
(in thousands)
Operating (loss) income
 
$
(9,163
)
 
$
(11,898
)
 
$
24,765

 
$
21,772

 
$
8,209

 
$
(11,128
)
 
$
22,557

Depreciation and amortization
 
16,503

 
27,150

 
4,441

 
11,379

 
404

 
890

 
60,767

Amortization recorded to cost of sales
 
100

 

 
195

 

 
1,458

 

 
1,753

Net unrealized losses (gains) on derivatives
 
732

 
(1,304
)
 
(3,387
)
 
2

 

 

 
(3,957
)
Inventory valuation adjustment
 

 

 

 

 
7,859

 

 
7,859

Lower of cost or market adjustments
 

 

 

 

 
731

 

 
731

Loss (gain) on disposal or impairment of assets, net
 
4,655

 
2,323

 
60

 
(62
)
 
(6,941
)
 
(1
)
 
34

Equity-based compensation expense
 

 

 

 

 

 
6,865

 
6,865

Acquisition expense
 

 

 

 
(2
)
 

 
380

 
378

Other income, net
 
721

 
1,214

 
4

 
19

 
16,220

 
1,829

 
20,007

Adjusted EBITDA attributable to unconsolidated entities
 
2,577

 
54

 

 
(111
)
 
1,867

 

 
4,387

Adjusted EBITDA attributable to noncontrolling interest
 

 
(667
)
 

 
(583
)
 

 

 
(1,250
)
Other
 
481

 
116

 
20

 

 

 

 
617

Adjusted EBITDA
 
$
16,606

 
$
16,988

 
$
26,098

 
$
32,414

 
$
29,807

 
$
(1,165
)
 
$
120,748


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Nine Months Ended December 31, 2017
 
 
Crude Oil
Logistics
 
Water
Solutions
 
Liquids
 
Retail
Propane
 
Refined
Products
and
Renewables
 
Corporate
and
Other
 
Consolidated
 
 
(in thousands)
Operating income (loss)
 
$
111,832

 
$
(10,075
)
 
$
(104,589
)
 
$
8,878

 
$
30,747

 
$
(56,031
)
 
$
(19,238
)
Depreciation and amortization
 
61,885

 
73,847

 
18,718

 
34,205

 
971

 
2,801

 
192,427

Amortization recorded to cost of sales
 
254

 

 
211

 

 
4,131

 

 
4,596

Net unrealized losses on derivatives
 
2,473

 
11,526

 
2,763

 
89

 

 

 
16,851

Inventory valuation adjustment
 

 

 

 

 
6,439

 

 
6,439

Lower of cost or market adjustments
 
5,207

 

 

 

 
297

 

 
5,504

(Gain) loss on disposal or impairment of assets, net
 
(111,290
)
 
3,114

 
117,515

 
2,004

 
(22,585
)
 

 
(11,242
)
Equity-based compensation expense
 

 

 

 

 

 
27,114

 
27,114

Acquisition expense
 

 

 

 

 

 
132

 
132

Other income, net
 
99

 
210

 
100

 
280

 
486

 
4,938

 
6,113

Adjusted EBITDA attributable to unconsolidated entities
 
11,507

 
425

 

 
891

 
3,125

 

 
15,948

Adjusted EBITDA attributable to noncontrolling interest
 

 
(619
)
 

 
(385
)
 

 

 
(1,004
)
Revaluation of liabilities
 

 
5,600

 

 

 

 

 
5,600

Other
 
3,790

 
276

 
64

 
(1,041
)
 

 

 
3,089

Adjusted EBITDA
 
$
85,757

 
$
84,304

 
$
34,782

 
$
44,921

 
$
23,611

 
$
(21,046
)
 
$
252,329

 
 
Nine Months Ended December 31, 2016
 
 
Crude Oil
Logistics
 
Water
Solutions
 
Liquids
 
Retail
Propane
 
Refined
Products
and
Renewables
 
Corporate
and
Other
 
Consolidated
 
 
(in thousands)
Operating (loss) income
 
$
(28,827
)
 
$
63,136

 
$
33,092

 
$
10,553

 
$
169,365

 
$
(66,690
)
 
$
180,629

Depreciation and amortization
 
34,496

 
76,713

 
13,315

 
31,771

 
1,237

 
2,744

 
160,276

Amortization recorded to cost of sales
 
284

 

 
585

 

 
4,229

 

 
5,098

Net unrealized losses (gains) on derivatives
 
951

 
(2,138
)
 
239

 
211

 

 

 
(737
)
Inventory valuation adjustment
 

 

 

 

 
40,552

 

 
40,552

Lower of cost or market adjustments
 

 

 

 

 
839

 

 
839

Loss (gain) on disposal or impairment of assets, net
 
14,617

 
(91,958
)
 
109

 
(96
)
 
(126,101
)
 
(4
)
 
(203,433
)
Equity-based compensation expense
 

 

 

 

 

 
39,859

 
39,859

Acquisition expense
 

 

 

 

 

 
1,539

 
1,539

Other (expense) income, net
 
(589
)
 
1,524

 
67

 
339

 
19,099

 
5,420

 
25,860

Adjusted EBITDA attributable to unconsolidated entities
 
7,651

 
(9
)
 

 
(388
)
 
3,543

 

 
10,797

Adjusted EBITDA attributable to noncontrolling interest
 

 
(2,298
)
 

 
(442
)
 

 

 
(2,740
)
Other
 
1,276

 
279

 
60

 

 

 

 
1,615

Adjusted EBITDA
 
$
29,859

 
$
45,249

 
$
47,467

 
$
41,948

 
$
112,763

 
$
(17,132
)
 
$
260,154


Liquidity, Sources of Capital and Capital Resource Activities

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

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Our borrowing needs vary during the year due in part to the seasonal nature of our Liquids, Retail Propane and Refined Products and Renewables businesses. Our greatest working capital borrowing needs generally occur during the period of June through December, when we are building our natural gas liquids inventories in anticipation of the heating season as well as building our gasoline inventories in anticipation of the winter gasoline contango and blending season. Our working capital borrowing needs generally decline during the period of January through March, when the cash flows from our Retail Propane and Liquids segments are the greatest and gasoline inventories need to be minimized due to certain inventory requirements.

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

We believe that our anticipated cash flows from operations and the borrowing capacity under our Revolving Credit Facility (as defined herein) are sufficient to meet our liquidity needs. If our plans or assumptions change or are inaccurate, or if we make acquisitions, we may need to raise additional capital or sell assets. Our ability to raise additional capital, if necessary, depends on various factors and conditions, including market conditions. We cannot give any assurances that we can raise additional capital to meet these needs. Commitments or expenditures, if any, we may make toward any acquisition projects are at our discretion.

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

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

Class B Preferred Units

During the nine months ended December 31, 2017 , we issued 8,400,000 of our 9.00% Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”) representing limited partner interests at a price of $25.00 per unit for net proceeds of $202.7 million (net of the underwriters’ discount of $6.6 million and offering costs of $0.7 million ). See Note 10 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further description of the Class B Preferred Units.

Disposals

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

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

Long-Term Debt

Credit Agreement

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


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

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

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

Senior Secured Notes

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

Senior Unsecured Notes

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

Repurchases

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

Compliance

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

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

Revolving Credit Balances

The following table summarizes our Revolving Credit Facility borrowings for the periods indicated:
 
 
Average Balance
Outstanding
 
Lowest
Balance
 
Highest
Balance
 
 
(in thousands)
Nine Months Ended December 31, 2017
 
 
 
 
 
 
Expansion capital borrowings
 
$
139,704

 
$

 
$
397,000

Working capital borrowings
 
$
811,536

 
$
719,500

 
$
1,014,500

 
 
 
 
 
 
 
Nine Months Ended December 31, 2016
 
 
 
 
 
 
Expansion capital borrowings
 
$
1,133,071

 
$
638,000

 
$
1,359,000

Working capital borrowings
 
$
662,660

 
$
465,500

 
$
875,500


At-The-Market Program

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

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Common Unit Repurchase Program

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

Capital Expenditures, Acquisitions and Other Investments

The following table summarizes expansion and maintenance capital expenditures (which excludes additions for tank bottoms and line fill and has been prepared on the accrual basis), acquisitions and other investments for the periods indicated.
 
 
Capital Expenditures
 
 
 
Other
 
 
Expansion
 
Maintenance
 
Acquisitions
 
Investments (1)
 
 
(in thousands)
Three Months Ended December 31,
 
 
 
 
 
 
 
 
2017
 
$
39,143

 
$
12,156

 
$
1,047

 
$
13,724

2016
 
$
60,330

 
$
5,205

 
$
14,216

 
$
52

 
 
 
 
 
 
 
 
 
Nine Months Ended December 31,
 
 
 
 
 
 
 
 
2017
 
$
83,175

 
$
26,677

 
$
49,481

 
$
27,874

2016
 
$
246,167

 
$
17,901

 
$
127,513

 
$
42,737

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

The following table summarizes the sources (uses) of our cash flows for the periods indicated:
 
 
Nine Months Ended December 31,
Cash Flows Provided by (Used in)
 
2017
 
2016
 
 
(in thousands)
Operating activities, before changes in operating assets and liabilities
 
$
168,825

 
$
194,858

Changes in operating assets and liabilities
 
(164,764
)
 
(310,430
)
Operating activities
 
$
4,061

 
$
(115,572
)
Investing activities
 
$
105,052

 
$
(331,070
)
Financing activities
 
$
(92,908
)
 
$
447,393


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

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

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

a $177.2 million increase in proceeds from sales of assets due primarily to the sale of our previously held 50% interest in Glass Mountain and an increase in proceeds from the sale of excess pipe in our Crude Oil Logistics segment during the nine months ended December 31, 2017 and the sale of TLP common units we owned and Grassland during the nine months ended December 31, 2016 ;
a decrease in capital expenditures from $264.6 million during the nine months ended December 31, 2016 , primarily related to the Grand Mesa Pipeline, to $99.4 million during the nine months ended December 31, 2017 ;
a $50.1 million decrease in cash paid for acquisitions and investments in and transactions with unconsolidated entities during the nine months ended December 31, 2017 ;
a $20.0 million deposit received related to the potential sale of a portion of our Retail Propane segment during the nine months ended December 31, 2017 ; and
a $16.9 million payment to terminate a development agreement during the nine months ended December 31, 2016 .

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

$700.0 million in proceeds received from the issuance of the 2023 Notes during the nine months ended December 31, 2016 ;
an increase of $400.4 million for repayments and repurchases of all of our remaining outstanding senior secured notes and a portion of our senior unsecured notes during the nine months ended December 31, 2017 ;
a decrease of $76.2 million in proceeds received from the sale of our common units and preferred units during the nine months ended December 31, 2017 ;
an increase of $34.2 million in distributions paid to our general partners and common unit holders, preferred unitholders and noncontrolling interest owners during the nine months ended December 31, 2017 ; and
$26.2 million for the repurchase of a portion of our common units and warrants related to our Class A Preferred Units during the nine months ended December 31, 2017 .

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

an increase of $659.5 million in borrowings on our Revolving Credit Facility (net of repayments) during the nine months ended December 31, 2017 ; and
a $25.9 million release of contingent consideration liabilities related to the termination of a development agreement during the nine months ended December 31, 2016 .

Distributions Declared

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders as of the record date. See further discussion of our cash distribution policy in Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities included in our Annual Report.

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


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

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

Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2017 for our fiscal years ending thereafter:
 
 
 
 
Three Months Ending March 31,
 
Fiscal Year Ending March 31,
 
 
 
 
Total
 
2018
 
2019
 
2020
 
2021
 
2022
 
Thereafter
 
 
(in thousands)
Principal payments on long-term debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expansion capital borrowings
 
$
125,000

 
$

 
$

 
$

 
$

 
$
125,000

 
$

Working capital borrowings
 
1,014,500

 

 

 

 

 
1,014,500

 

Senior unsecured notes
 
1,796,925

 

 

 
360,781

 
 
 
367,048

 
1,069,096

Other long-term debt
 
11,684

 
604

 
2,939

 
2,318

 
5,470

 
286

 
67

Interest payments on long-term debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revolving Credit Facility (1)
 
238,503

 
15,289

 
62,004

 
62,004

 
62,004

 
37,202

 

Senior unsecured notes
 
622,879

 
21,878

 
118,235

 
108,990

 
99,745

 
99,745

 
174,286

Other long-term debt
 
1,187

 
174

 
498

 
341

 
157

 
14

 
3

Letters of credit
 
182,123

 

 

 

 

 
182,123

 

Future minimum lease payments under noncancelable operating leases
 
516,712

 
34,721

 
120,928

 
107,342

 
93,662

 
66,036

 
94,023

Future minimum throughput payments under noncancelable agreements (2)
 
107,394

 
13,001

 
52,042

 
42,351

 

 

 

Construction commitments (3)
 
6,211

 
3,650

 
2,561

 

 

 

 

Fixed-price commodity purchase commitments:
 

 
 
 
 
 
 
 
 
 
 
 
 
Crude oil
 
51,001

 
51,001

 

 

 

 

 

Natural gas liquids
 
21,941

 
20,600

 
1,341

 

 

 

 

Index-price commodity purchase commitments (4):
 

 
 
 
 
 
 
 
 
 
 
 
 
Crude oil (5)
 
2,972,749

 
427,214

 
790,287

 
511,636

 
438,851

 
357,603

 
447,158

Natural gas liquids
 
356,683

 
310,124

 
46,559

 

 

 

 

Total contractual obligations
 
$
8,025,492

 
$
898,256

 
$
1,197,394

 
$
1,195,763

 
$
699,889

 
$
2,249,557

 
$
1,337,475

 
(1)
The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at December 31, 2017 . See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for additional information on our Credit Agreement.
(2)
We have executed noncancelable agreements with crude oil operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity. Under certain agreements we have the ability to recover minimum shipping fees previously paid if our shipping volumes exceed the minimum monthly shipping commitment during each month remaining under the agreement. See Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report for additional information.
(3)
At December 31, 2017 , construction commitments primarily relate to the expansion of the Lucerne, Colorado crude oil tank storage.
(4)
Index prices are based on a forward price curve at December 31, 2017 . A theoretical change of $0.10 per gallon of natural gas liquids in the underlying commodity price at December 31, 2017 would result in a change of $37.0 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel of crude oil in the underlying commodity price at December 31, 2017 would result in a change of $59.1 million in the value of our index-price crude oil purchase commitments. See Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report for further detail of the commitments.

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(5)
Our crude oil index-price purchase commitments exceed our crude oil index-price sales commitments (see Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report) due primarily to our long-term purchase commitments for crude oil that we purchase and ship on the Grand Mesa pipeline. As these purchase commitments are deliver-or-pay contracts, we have not entered into corresponding long-term sales contracts for volumes we may not receive.

Off-Balance Sheet Arrangements

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

Environmental Legislation

See our Annual Report for a discussion of proposed environmental legislation and regulations that, if enacted, could result in increased compliance and operating costs. However, at this time we cannot predict the structure or outcome of any future legislation or regulations or the eventual cost we could incur in compliance.

Recent Accounting Pronouncements

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

Critical Accounting Policies

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


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Item 3.      Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

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

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

Commodity Price and Credit Risk

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

Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions. At December 31, 2017 , our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.

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

We engage in various types of forward contracts and financial derivative transactions to reduce the effect of price volatility on our product costs, to protect the value of our inventory positions, and to help ensure the availability of product during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes when we have a matching purchase commitment from our wholesale and retail customers. We may experience net unbalanced positions from time to time. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio.

Although we use financial derivative instruments to reduce the market price risk associated with forecasted transactions, we do not account for financial derivative transactions as hedges. We record the changes in fair value of these financial derivative transactions within cost of sales in our unaudited condensed consolidated statements of operations. The following table summarizes the hypothetical impact on the December 31, 2017 fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands):
 
Increase
(Decrease)
To Fair Value
Crude oil (Crude Oil Logistics segment)
$
(8,840
)
Propane (Liquids segment)
$
744

Other products (Liquids segment)
$
(2,625
)
Gasoline (Refined Products and Renewables segment)
$
(23,456
)
Diesel (Refined Products and Renewables segment)
$
(18,277
)
Ethanol (Refined Products and Renewables segment)
$
(3,728
)
Biodiesel (Refined Products and Renewables segment)
$
3,785

Canadian dollars (Liquids segment)
$
705



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Fair Value

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

Item 4.
Controls and Procedures

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

We completed an evaluation under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures at December 31, 2017 . Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of December 31, 2017 , such disclosure controls and procedures were effective to provide the reasonable assurance described above.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) of the Exchange Act) during the three months ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.


88

Table of Contents


PART II - OTHER INFORMATION

Item 1.      Legal Proceedings

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

Item 1A.      Risk Factors

There have been no material changes in the risk factors previously disclosed in Part I, Item 1A–“Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended March 31, 2017 , as supplemented and updated by Part II, Item 1A–“Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2017.

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

Common Unit Repurchase Program

On August 29, 2017, the board of directors of our general partner authorized a common unit repurchase program, under which we may repurchase up to $15.0 million of our outstanding common units through December 31, 2017 from time to time in the open market or in other privately negotiated transactions. The common unit repurchase program authorization does not obligate us to repurchase any dollar amount or number of our common units. The following table summarizes the repurchase of common units during the three months ended December 31, 2017 :
 
 
 
 
 
 
Total Number of
 
 
 
 
 
 
 
 
Common Units
 
Approximate Dollar Value
 
 
Total Number of
 
Average Price
 
Purchased as Part
 
of Common Units
 
 
Common Units
 
Paid Per
 
of Publicly Announced
 
that May Yet Be Purchased
Period
 
Purchased
 
Common Unit
 
Program
 
Under the Program
October 1-31, 2017
 

 
$

 

 
$
3,847,062

November 1-30, 2017
 
327,309

 
$
12.02

 
323,213

 
$

December 1-31, 2017
 

 
$

 

 
$

Total
 
327,309

 
 
 
323,213

 
$


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

Item 3.      Defaults Upon Senior Securities

Not applicable.

Item 4.      Mine Safety Disclosures

Not applicable.

Item 5.      Other Information

Amendment to Credit Agreement

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


89

Table of Contents


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

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

Item 6.      Exhibits
Exhibit Number
 
Exhibit
10.1*
 
12.1*
 
31.1*
 
31.2*
 
32.1*
 
32.2*
 
101.INS**
 
XBRL Instance Document
101.SCH**
 
XBRL Schema Document
101.CAL**
 
XBRL Calculation Linkbase Document
101.DEF**
 
XBRL Definition Linkbase Document
101.LAB**
 
XBRL Label Linkbase Document
101.PRE**
 
XBRL Presentation Linkbase Document
 
*
Exhibits filed with this report.
**
The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Unaudited Condensed Consolidated Balance Sheets at December 31, 2017 and March 31, 2017 , (ii) Unaudited Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2017 and 2016 , (iii) Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and nine months ended December 31, 2017 and 2016 , (iv) Unaudited Condensed Consolidated Statement of Changes in Equity for the nine months ended December 31, 2017 , (v) Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2017 and 2016 , and (vi) Notes to Unaudited Condensed Consolidated Financial Statements.


90

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


91


Exhibit 10.1

AMENDMENT NO. 3 TO CREDIT AGREEMENT

AMENDMENT NO. 3 TO CREDIT AGREEMENT , dated as of February 5, 2018 (this “ Amendment ”), to the Amended and Restated Credit Agreement dated as of February 14, 2017 (as amended by Amendment No. 1 to Credit Agreement dated as of March 31, 2017, Amendment No. 2 to Credit Agreement dated June 2, 2017 and as otherwise amended, supplemented and modified from time to time, the “ Credit Agreement ”) among NGL ENERGY PARTNERS LP, a Delaware limited partnership (“ Parent ”), NGL ENERGY OPERATING LLC, a Delaware limited liability company (“ Borrowers’ Agent ”), each subsidiary of the Parent identified as a “Borrower” under the Credit Agreement (together with the Borrowers’ Agent, each, a “ Borrower ” and collectively, the “ Borrowers ”), each subsidiary of Parent identified as a “Guarantor” under the Credit Agreement (together with the Parent, each, a “ Guarantor ” and collectively, the “ Guarantors ”) DEUTSCHE BANK AG, NEW YORK BRANCH, as technical agent (in such capacity, together with its successors in such capacity, the “ Technical Agent ”) and DEUTSCHE BANK TRUST COMPANY AMERICAS (“ DBTCA ”), as administrative agent for the Secured Parties (in such capacity, together with its successors in such capacity, the “ Administrative Agent ”) and as collateral agent for the Secured Parties (as defined below) (in such capacity, together with its successors in such capacity, the “ Collateral Agent ”) and each financial institution identified as a “Lender” or an “Issuing Bank” under the Credit Agreement (each, a “ Lender ” and together with the Technical Agent, the Administrative Agent and the Collateral Agent, the “ Secured Parties ”).
RECITALS
WHEREAS, the Borrowers have requested certain amendments to the Credit Agreement; and
WHEREAS, the Lenders have agreed to amend the Credit Agreement solely upon the terms and conditions set forth herein;
NOW, THEREFORE, in consideration of the premises and the agreements hereinafter set forth, the parties hereto hereby agree as follows:
1. Defined Terms . Unless otherwise noted herein, terms defined in the Credit Agreement and used herein shall have the respective meanings given to them in the Credit Agreement.

2. Amendment to Section 1.1 (Certain Defined Terms) of the Credit Agreement . The defined term “Consolidated EBITDA” in Section 1.1 of the Credit Agreement is hereby amended by adding the following sentence at the end of the existing defined term:

“Solely for the two fiscal quarters ending December 31, 2017 and March 31, 2018, Consolidated EBITDA may be adjusted (without duplication) to include the Accrued Blenders Tax Credits; provided that such adjustments shall not exceed in the aggregate $26,800,000, whether applied in a single fiscal quarter or applied over such two fiscal quarters, determined by the Borrowers’ Agent in its discretion, which determination shall be confirmed to the Administrative Agent in writing or other authenticated record; provided further that if by June 30, 2018, 26 U.S.C. § 6426(c)(6) of the Code has not been amended to permit the accrual of tax credits under 26 U.S.C. § 6426(c) for calendar year 2017, each determination of Consolidated EBITDA on and after June 30, 2018 that includes a fiscal quarter ending either December 31, 2017 or March 31, 2018, shall be made without including the Accrued Blenders Tax Credit.”
3. Amendment to Section 1.1 (Certain Defined Terms) of the Credit Agreement . Section 1.1 of the Credit Agreement is hereby amended by adding the following new defined terms “Accrued Blenders Tax Credits,” “Blenders Tax Credits” and “Retail West Disposition” in their respective alphabetical order therein:

““ Accrued Blenders Tax Credits ” means the Blenders Tax Credit that would have been properly determined under 26 U.S.C. § 6426(c) of the Code and accrued to the Credit Parties for their biodiesel related activities between January 1, 2017 and December 31, 2017 had the effectiveness of 26 U.S.C. § 6426(c) of the Code not terminated as of December 31, 2016; provided that such Blenders Tax Credits would not otherwise be eligible to be recognized by the Credit Parties under GAAP accounting rules.”
““ Blenders Tax Credits ” means a tax credit available with respect to biodiesel fuel mixtures pursuant to 26 U.S.C. § 6426(c) of the Code for certain taxpayers that used or sold certain biodiesel mixtures.”




““ Retail West Disposition ” means the sale of 100% of the issued and outstanding limited liability company membership interests of Hicksgas, LLC, a Delaware limited liability company, pursuant to the terms and conditions of the Retail West Purchase Agreement.”
““ Retail West Purchase Agreement ” means that certain Membership Interest Purchase Agreement dated as of November 6, 2017, entered by and among, NGL Propane LLC, a Delaware limited liability company, Parent, DCC LPG Holdings, Inc., a Delaware corporation, and DCC Energy UK Limited.”
4. Amendment to Section 7.4 (Dispositions) of the Credit Agreement . Section 7.4 of the Credit Agreement is hereby amended by inserting the below at the end of existing clause (5) of such section:

provided further that this clause 5 shall not be applicable to the Retail West Disposition and, for the avoidance of doubt, with respect to any determination as to whether the Credit Parties have exceeded the 7.5% limit on Dispositions for fiscal year 2018, the assets sold in the Retail West Disposition shall be excluded from such determination.”
5. Amendment to Section 7.4 (Dispositions) of the Credit Agreement . Section 7.4 of the Credit Agreement is hereby further amended as follows: (i) by deleting the “and” as it appears at the end of clause (7) thereof, (ii) by deleting the “.” at the end of clause (8) thereof and inserting in lieu thereof “; and” and (iii) by inserting the following as a new clause in the appropriate numeric order:

(9)    “the Credit Parties may consummate the Retail West Disposition.”
6. Representations and Warranties; No Default . To induce the Lenders to enter into this Amendment, each Credit Party that is a party hereto (by delivery of its respective counterpart to this Amendment) hereby (i) represents and warrants to the Administrative Agent and the Lenders that after giving effect to this Amendment, its representations and warranties contained in the Credit Agreement and other Loan Documents are true and correct in all material respects on and as of the date hereof with the same effect as though made on and as of the date hereof, except to the extent such representations and warranties expressly relate to an earlier date (in which case such representations and warranties were true and correct in all material respects as of such earlier date); (ii) represents and warrants to the Administrative Agent and the Lenders that it (x) has the requisite power and authority to make, deliver and perform this Amendment; (y) has taken all necessary corporate, limited liability company, limited partnership or other action to authorize its execution, delivery and performance of this Amendment, and (z) has duly executed and delivered this Amendment and (iii) certifies that no Default or Event of Default has occurred and is continuing under the Credit Agreement (after giving effect to this Amendment) or will result from the making of this Amendment.

7. Effectiveness of Amendments . This Amendment shall become effective upon the first date on which each of the following conditions has been satisfied:

(a) Amendment Documents . The Administrative Agent shall have received this Amendment, duly executed and delivered by each of the Credit Parties, and by Lenders constituting the Required Lenders.

(b) Fees and Expenses . The Borrowers shall, upon demand, pay to the Administrative Agent (i) the aggregate amount of the amendment work fees due to the Lenders party hereto in accordance with the offer made in the amendment request prepared in connection with this Amendment and (ii) any and all other reasonable fees, costs and expenses that are for the account of the Borrowers pursuant to Section 10.9 of the Credit Agreement, including all such fees, costs and expenses incurred in connection with this Amendment.

(c) Proceedings and Documents . All corporate and other proceedings pertaining directly to this Amendment and all documents, instruments directly incident to this Amendment shall be satisfactory to the required Lenders and their respective counsel and the Technical Agent shall have received all such counterpart originals or certified or other copies of such documents as the Technical Agent may reasonably request.

8. Retail West Releases; Proceeds Application . By executing this Amendment, each Lender party hereto consents, subject to the consummation of the Retail West Disposition in accordance with the terms of the Retail West Purchase Agreement, to the release of (and authorizes the Collateral Agent to release) Hicksgas, LLC from its Guaranty and its other obligations under the Loan Documents. The Credit Parties hereby agree to use the proceeds (net of expenses) of the Retail West Disposition to pay down existing Indebtedness no later than five (5) Business days after the Retail West Disposition is consummated.


2



9. Limited Effect . Except as expressly provided hereby, all of the terms and provisions of the Credit Agreement and the other Loan Documents are and shall remain in full force and effect. The amendments contained herein shall not be construed as a waiver or amendment of any other provision of the Credit Agreement or the other Loan Documents or for any purpose, except as expressly set forth herein, or a consent to any further or future action on the part of any Credit Party that would require the waiver or consent of the Lenders. This Amendment shall constitute a “Loan Document” for all purposes of the Credit Agreement and the other Loan Documents.

10. GOVERNING LAW . THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES UNDER THIS AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE SUBSTANTIVE LAW OF THE STATE OF NEW YORK.

11. Counterparts . This Amendment may be executed in any number of counterparts, all of which taken together shall constitute one and the same agreement, and any of the parties hereto may execute this Amendment by signing any such counterpart. Delivery of an executed counterpart hereof by facsimile or email transmission shall be effective as delivery of a manually executed counterpart hereof.

12. Headings . Section or other headings contained in this Amendment are for reference purposes only and shall not in any way affect the meaning or interpretation of this Amendment.

13. Guarantor Acknowledgement . Each Guarantor party hereto hereby (i) consents to the modifications to the Credit Agreement contemplated by this Amendment and (ii) acknowledges and agrees that its guaranty pursuant to Section 10.18 of the Credit Agreement is, and shall remain, in full force and effect after giving effect to the Amendment.

14. Lender Acknowledgement . Each undersigned Lender, by its signature hereto, hereby authorizes and directs DBTCA in its capacity as Administrative Agent and as Collateral Agent to execute this Amendment.

[ Signature Pages Follow ]


3



IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorized officers as of the day and year first above written.

BORROWERS’ AGENT AND BORROWER :


NGL ENERGY OPERATING LLC,
a Delaware limited liability company



By:
/s/ Robert W. Karlovich III
Name:
Robert W. Karlovich III
Title:
Chief Financial Officer and Executive Vice President



PARENT :


NGL ENERGY PARTNERS LP,
a Delaware limited partnership



By:
/s/ Robert W. Karlovich III
Name:
Robert W. Karlovich III
Title:
Chief Financial Officer and Executive Vice President

Signature Page to Amendment No. 3 to Credit Agreement





GUARANTORS :
ANTICLINE DISPOSAL, LLC
CENTENNIAL ENERGY, LLC
CENTENNIAL GAS LIQUIDS ULC
CHOYA OPERATING, LLC
GRAND MESA PIPELINE, LLC
HICKSGAS, LLC
HIGH SIERRA CRUDE OIL AND MARKETING, LLC
HIGH SIERRA ENERGY, LP
NGL CRUDE CANADA, ULC
NGL CRUDE CANADA HOLDINGS, LLC
NGL CRUDE CUSHING, LLC
NGL CRUDE LOGISTICS, LLC
NGL CRUDE PIPELINES, LLC
NGL CRUDE TERMINALS, LLC
NGL CRUDE TRANSPORTATION, LLC
NGL ENERGY EQUIPMENT, LLC
NGL ENERGY FINANCE CORP.
NGL ENERGY HOLDINGS II, LLC
NGL ENERGY LOGISTICS, LLC
NGL ENERGY OPERATING LLC
NGL ENERGY PARTNERS LP
NGL LIQUIDS, LLC
NGL-MA, LLC
NGL-MA REAL ESTATE, LLC
NGL MARINE, LLC
NGL MILAN INVESTMENTS, LLC
NGL-NE REAL ESTATE, LLC
NGL PROPANE, LLC
NGL SHIPPING AND TRADING, LLC
NGL SUPPLY TERMINAL COMPANY, LLC
NGL SUPPLY TERMINAL SOLUTION MINING, LLC
NGL SUPPLY WHOLESALE, LLC
NGL WATER SOLUTIONS, LLC
NGL WATER SOLUTIONS BAKKEN, LLC
NGL WATER SOLUTIONS DJ, LLC
NGL WATER SOLUTIONS EAGLE FORD, LLC
NGL WATER SOLUTIONS MID-CONTINENT, LLC
NGL WATER SOLUTIONS PERMIAN, LLC
OPR, LLC
OSTERMAN PROPANE, LLC
SAWTOOTH NGL CAVERNS, LLC
TRANSMONTAIGNE LLC
TRANSMONTAIGNE PRODUCT SERVICES LLC
TRANSMONTAIGNE SERVICES LLC


By:
/s/ Robert W. Karlovich III
Name:
Robert W. Karlovich III
Title:
Chief Financial Officer and Executive Vice President

Signature Page to Amendment No. 3 to Credit Agreement





SECURED PARTIES :

DEUTSCHE BANK TRUST COMPANY AMERICAS, as Administrative Agent and as Collateral Agent



By:
/s/ Chris Chapman
Name:
Chris Chapman
Title:
Director


By:
/s/ Shai Bandner
Name:
Shai Bandner
Title:
Director



DEUTSCHE BANK AG, NEW YORK BRANCH,
as a Lender, as Swingline Lender, as an Issuing Bank and as Technical Agent



By:
/s/ Chris Chapman
Name:
Chris Chapman
Title:
Director


By:
/s/ Shai Bandner
Name:
Shai Bandner
Title:
Director




Signature Page to Amendment No. 3 to Credit Agreement





ROYAL BANK OF CANADA,
as a Lender



By:
/s/ Jason York
Name:
Jason York
Title:
Authorized Signatory



BNP PARIBAS,
as a Lender and Issuing Bank



By:
/s/ Delphine Gaudiot
Name:
Delphine Gaudiot
Title:
Director


By:
/s/ Redi Meshi
Name:
Redi Meshi
Title:
Vice President



PNC BANK, NATIONAL ASSOCIATION
as a Lender



By:
/s/ John Berry
Name:
John Berry
Title:
Senior Vice President



BARCLAYS BANK PLC,
as a Lender



By:
/s/ Sydney G. Dennis
Name:
Sydney G. Dennis
Title:
Director

Signature Page to Amendment No. 3 to Credit Agreement




ABN AMRO CAPITAL USA LLC,
as a Lender



By:
/s/ Darrell Holley
Name:
Darrell Holley
Title:
Managing Director


By:
/s/ Anna C. Ferreira
Name:
Anna C. Ferreira
Title:
Vice President



TORONTO DOMINION BANK, NEW YORK BRANCH,
as a Lender



By:
/s/ Annie Dorval
Name:
Annie Dorval
Title:
Authorized Signatory



WELLS FARGO BANK, NATIONAL ASSOCIATION,
as a Lender



By:
/s/ Jacob L. Osterman
Name:
Jacob L. Osterman
Title:
Director



MIZUHO BANK, LTD.,
as a Lender



By:
/s/ Leon Mo
Name:
Leon Mo
Title:
Authorized Signatory

Signature Page to Amendment No. 3 to Credit Agreement




UBS AG, STAMFORD BRANCH,
as a Lender



By:
/s/ Houssem Daly
Name:
Houssem Daly
Title:
Associate Director


By:
/s/ Darlene Arias
Name:
Darlene Arias
Title:
Director



CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH,
as a Lender



By:
/s/ Nupur Kumar
Name:
Nupur Kumar
Title:
Authorized Signatory


By:
/s/ Christopher Zybrick
Name:
Christopher Zybrick
Title:
Authorized Signatory



GOLDMAN SACHS BANK USA,
as a Lender



By:
/s/ Chris Lam
Name:
Chris Lam
Title:
Authorized Signatory



MACQUARIE BANK LIMITED,
as a Lender



By:
            
Name:        
Title:    


By:
            
Name:        
Title:

Signature Page to Amendment No. 3 to Credit Agreement




RAYMOND JAMES BANK, N.A.,
as a Lender



By:
/s/ Scott G. Axelrod
Name:
Scott G. Axelrod
Title:
Senior Vice President



CITIZENS BANK, N.A.,
as a Lender



By:
/s/ Scott Donaldson
Name:
Scott Donaldson
Title:
Senior Vice President














Signature Page to Amendment No. 3 to Credit Agreement



Exhibit 12.1

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS (LOSS) TO FIXED CHARGES
AND COMBINED FIXED CHARGES AND PREFERRED UNIT DISTRIBUTIONS
(in Thousands, except ratio amounts)
 
 
Nine Months Ended December 31,
 
 Fiscal Year Ended March 31,
 
 
2017
 
2017
 
2016
 
2015
 
2014
 
2013
 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS (LOSS):
 
 
 
 
 
 
 
 
 
 
 
 
(Loss) income before income taxes
 
$
(179,583
)
 
$
145,813

 
$
(187,464
)
 
$
46,571

 
$
49,695

 
$
50,065

Income before income taxes attributable to noncontrolling interests
 
(221
)
 
(6,832
)
 
(11,832
)
 
(12,887
)
 
(1,103
)
 
(250
)
Loss before income taxes attributable to redeemable noncontrolling interests
 
261

 

 

 

 

 

Fixed charges
 
205,361

 
189,465

 
146,401

 
151,956

 
91,622

 
66,824

Total earnings (loss)
 
$
25,818

 
$
328,446

 
$
(52,895
)
 
$
185,640

 
$
140,214

 
$
116,639

 
 
 
 
 
 
 
 
 
 
 
 
 
FIXED CHARGES:
 
 
 
 
 
 
 
 
 
 
 
 
Interest expense
 
$
151,249

 
$
150,478

 
$
133,089

 
$
110,123

 
$
58,854

 
$
32,994

Loss (gain) on early extinguishment of debt
 
22,479

 
(2,449
)
 
(28,532
)
 

 

 
5,769

Portion of rental expense estimated to relate to interest (1)
 
31,633

 
41,436

 
41,844

 
41,833

 
32,768

 
28,061

Fixed charges
 
$
205,361

 
$
189,465

 
$
146,401

 
$
151,956

 
$
91,622

 
$
66,824

 
 
 
 
 
 
 
 
 
 
 
 
 
PREFERRED UNIT DISTRIBUTIONS
 
25,017

 
14,693

 

 

 

 

Combined fixed charges and preferred unit distributions
 
$
230,378

 
$
204,158

 
$
146,401

 
$
151,956

 
$
91,622

 
$
66,824

 
 
 
 
 
 
 
 
 
 
 
 
 
Ratio of earnings to fixed charges (2) (3)
 

 
1.73

 

 
1.22

 
1.53

 
1.75

Ratio of earnings to combined fixed charges and preferred unit distributions (2)
 

 
1.61

 
 
 
 
 
 
 
 
 
(1)
Represents one-third of the total operating lease rental expense, which is that portion estimated to represent interest.
(2)
The ratio of earnings to fixed charges was less than 1:1 for the nine months ended December 31, 2017 . NGL Energy Partners LP would have needed to generate an additional $179.5 million of earnings to achieve a ratio of 1:1. The ratio of earnings to combined fixed charges and preferred unit distributions was less than 1:1 for the nine months ended December 31, 2017 . NGL Energy Partners LP would have needed to generate an additional $204.6 million of earnings to achieve a ratio of 1:1.
(3)
The ratio of earnings to fixed charges was less than 1:1 for the fiscal year ended March 31, 2016. NGL Energy Partners LP would have needed to generate an additional $199.3 million of earnings to achieve a ratio of 1:1.




Exhibit 31.1
CERTIFICATION

I, H. Michael Krimbill , certify that:

1.
I have reviewed this Quarterly Report on Form 10-Q of NGL Energy Partners LP;

2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 9, 2018
/s/ H. Michael Krimbill
 
H. Michael Krimbill
 
Chief Executive Officer of NGL Energy Holdings LLC, the general partner of NGL Energy Partners LP





Exhibit 31.2
CERTIFICATION

I, Robert W. Karlovich III , certify that:

1.
I have reviewed this Quarterly Report on Form 10-Q of NGL Energy Partners LP;

2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 9, 2018
/s/ Robert W. Karlovich III
 
Robert W. Karlovich III
 
Chief Financial Officer of NGL Energy Holdings LLC, the general partner of NGL Energy Partners LP
 





Exhibit 32.1

CERTIFICATION
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Quarterly Report of NGL Energy Partners LP (the “ Partnership ”) on Form 10-Q for the fiscal quarter ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “ Report ”), I, H. Michael Krimbill , Chief Executive Officer of NGL Energy Holdings LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“ Section 906 ”), that, to my knowledge:

1.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: February 9, 2018
/s/ H. Michael Krimbill
 
H. Michael Krimbill
 
Chief Executive Officer of NGL Energy Holdings LLC, the general partner of NGL Energy Partners LP

This certification is being furnished solely pursuant to Section 906 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.





Exhibit 32.2

CERTIFICATION
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Quarterly Report of NGL Energy Partners LP (the “ Partnership ”) on Form 10-Q for the fiscal quarter ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “ Report ”), I, Robert W. Karlovich III , Chief Financial Officer of NGL Energy Holdings LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“ Section 906 ”), that, to my knowledge:

1.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: February 9, 2018
/s/ Robert W. Karlovich III
 
Robert W. Karlovich III
 
Chief Financial Officer of NGL Energy Holdings LLC, the general partner of NGL Energy Partners LP

This certification is being furnished solely pursuant to Section 906 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.