NGL Energy Partners LP - FORM 10-Q - November 7, 2017

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

FORM 10-Q

(Mark One)

x    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2017
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 November 3, 2017, there were 120,512,692 common units issued and outstanding.



TABLE OF CONTENTS

 
 
 
 
 
 
 
 
 
 
 
 


i

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;

1

•
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.


2

PART I - FINANCIAL INFORMATION

Item 1.    Financial Statements

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Unaudited Condensed Consolidated Balance Sheets
(in Thousands, except unit amounts)
 
September 30, 2017
 
March 31, 2017
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
18,407

 
$
12,264

Accounts receivable-trade, net of allowance for doubtful accounts of $5,799 and $5,234, respectively
841,645

 
800,607

Accounts receivable-affiliates
2,918

 
6,711

Inventories
570,733

 
561,432

Prepaid expenses and other current assets
112,517

 
103,193

Total current assets
1,546,220

 
1,484,207

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $432,820 and $375,594, respectively
1,768,485

 
1,790,273

GOODWILL
1,339,416

 
1,451,716

INTANGIBLE ASSETS, net of accumulated amortization of $435,457 and $414,605, respectively
1,112,535

 
1,163,956

INVESTMENTS IN UNCONSOLIDATED ENTITIES
198,281

 
187,423

LOAN RECEIVABLE-AFFILIATE
4,160

 
3,200

OTHER NONCURRENT ASSETS
240,561

 
239,604

Total assets
$
6,209,658

 
$
6,320,379

LIABILITIES AND EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable-trade
$
635,312

 
$
658,021

Accounts payable-affiliates
4,749

 
7,918

Accrued expenses and other payables
227,069

 
207,125

Advance payments received from customers
80,378

 
35,944

Current maturities of long-term debt
42,373

 
29,590

Total current liabilities
989,881

 
938,598

LONG-TERM DEBT, net of debt issuance costs of $29,094 and $33,458, respectively, and current maturities
2,993,461

 
2,963,483

OTHER NONCURRENT LIABILITIES
175,885

 
184,534

COMMITMENTS AND CONTINGENCIES (NOTE 9)


 


 
 
 
 
CLASS A 10.75% CONVERTIBLE PREFERRED UNITS, 19,942,169 and 19,942,169 preferred units issued and outstanding, respectively
71,009

 
63,890

REDEEMABLE NONCONTROLLING INTEREST
3,129

 
3,072

 
 
 
 
EQUITY:
 
 
 
General partner, representing a 0.1% interest, 120,633 and 120,300 notional units, respectively
(50,872
)
 
(50,529
)
Limited partners, representing a 99.9% interest, 120,512,692 and 120,179,407 common units issued and outstanding, respectively
1,819,491

 
2,192,413

Class B preferred limited partners, 8,400,000 and 0 preferred units issued and outstanding, respectively
202,755

 
—

Accumulated other comprehensive loss
(2,262
)
 
(1,828
)
Noncontrolling interests
7,181

 
26,746

Total equity
1,976,293

 
2,166,802

Total liabilities and equity
$
6,209,658

 
$
6,320,379

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

3

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Unaudited Condensed Consolidated Statements of Operations
(in Thousands, except unit and per unit amounts)
 
 
Three Months Ended September 30,
 
Six Months Ended September 30,
 
 
2017
 
2016
 
2017
 
2016
REVENUES:
 
 
 
 
 
 
 
 
Crude Oil Logistics
 
$
437,022

 
$
349,885

 
$
941,937

 
$
775,836

Water Solutions
 
51,032

 
39,733

 
97,999

 
75,486

Liquids
 
393,123

 
234,260

 
670,937

 
439,309

Retail Propane
 
64,700

 
51,090

 
131,772

 
111,477

Refined Products and Renewables
 
2,977,206

 
2,370,322

 
5,861,843

 
4,364,885

Other
 
246

 
248

 
407

 
515

Total Revenues
 
3,923,329

 
3,045,538

 
7,704,895

 
5,767,508

COST OF SALES:
 
 
 
 
 
 
 
 
Crude Oil Logistics
 
401,170

 
340,518

 
870,640

 
745,748

Water Solutions
 
2,674

 
(1,807
)
 
2,827

 
3,394

Liquids
 
377,569

 
209,283

 
648,643

 
400,275

Retail Propane
 
31,320

 
20,691

 
60,956

 
45,511

Refined Products and Renewables
 
2,957,867

 
2,359,932

 
5,829,569

 
4,300,019

Other
 
121

 
113

 
194

 
223

Total Cost of Sales
 
3,770,721

 
2,928,730

 
7,412,829

 
5,495,170

OPERATING COSTS AND EXPENSES:
 
 
 
 
 
 
 
 
Operating
 
75,970

 
73,255

 
152,439

 
148,427

General and administrative
 
23,480

 
27,926

 
48,471

 
69,797

Depreciation and amortization
 
65,208

 
50,603

 
129,087

 
99,509

Loss (gain) on disposal or impairment of assets, net
 
111,452

 
852

 
100,238

 
(203,467
)
Revaluation of liabilities
 
5,600

 
—

 
5,600

 
—

Operating (Loss) Income
 
(129,102
)
 
(35,828
)
 
(143,769
)
 
158,072

OTHER INCOME (EXPENSE):
 
 
 
 
 
 

 
 

Equity in earnings of unconsolidated entities
 
2,028

 
53

 
3,844

 
447

Revaluation of investments
 
—

 
—

 
—

 
(14,365
)
Interest expense
 
(50,233
)
 
(33,442
)
 
(99,459
)
 
(63,880
)
Gain (loss) on early extinguishment of liabilities, net
 
1,943

 
938

 
(1,338
)
 
30,890

Other income, net
 
1,896

 
2,081

 
4,006

 
5,853

(Loss) Income Before Income Taxes
 
(173,468
)
 
(66,198
)
 
(236,716
)
 
117,017

INCOME TAX EXPENSE
 
(111
)
 
(460
)
 
(570
)
 
(922
)
Net (Loss) Income
 
(173,579
)
 
(66,658
)
 
(237,286
)
 
116,095

LESS: NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
(80
)
 
59

 
(132
)
 
(5,774
)
LESS: NET LOSS ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS
 
288

 
—

 
685

 
—

NET (LOSS) INCOME ATTRIBUTABLE TO NGL ENERGY PARTNERS LP
 
(173,371
)
 
(66,599
)
 
(236,733
)
 
110,321

LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS
 
(16,098
)
 
(8,668
)
 
(25,782
)
 
(12,052
)
LESS: NET LOSS (INCOME) ALLOCATED TO GENERAL PARTNER
 
154

 
45

 
194

 
(158
)
LESS: REPURCHASE OF WARRANTS
 
—

 
—

 
(349
)
 
—

NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS
 
$
(189,315
)
 
$
(75,222
)
 
$
(262,670
)
 
$
98,111

BASIC (LOSS) INCOME PER COMMON UNIT
 
$
(1.56
)
 
$
(0.71
)
 
$
(2.17
)
 
$
0.93

DILUTED (LOSS) INCOME PER COMMON UNIT
 
$
(1.56
)
 
$
(0.71
)
 
$
(2.17
)
 
$
0.91

BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING
 
121,314,636

 
106,186,389

 
120,927,400

 
105,183,556

DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING
 
121,314,636

 
106,186,389

 
120,927,400

 
107,997,549


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

4

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Unaudited Condensed Consolidated Statements of Comprehensive (Loss) Income
(in Thousands)
 
 
Three Months Ended September 30,
 
Six Months Ended September 30,
 
 
2017
 
2016
 
2017
 
2016
Net (loss) income
 
$
(173,579
)
 
$
(66,658
)
 
$
(237,286
)
 
$
116,095

Other comprehensive loss
 
(59
)
 
(333
)
 
(434
)
 
(485
)
Comprehensive (loss) income
 
$
(173,638
)
 
$
(66,991
)
 
$
(237,720
)
 
$
115,610


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


5

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Unaudited Condensed Consolidated Statement of Changes in Equity
Six Months Ended September 30, 2017
(in Thousands, except unit amounts)
 
 
 
 
Limited Partners
 
 
 
 
 
 
 
 
 
 
Class B Preferred
 
Common
 
Accumulated
Other
 
 
 
 
 
 
General
Partner
 
Units
 
Amount
 

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

 
$
—

 
120,179,407

 
$
2,192,413

 
$
(1,828
)
 
$
26,746

 
$
2,166,802

Distributions to general and common unit partners and preferred unitholders (Note 10)
 
(161
)
 
—

 
—

 
—

 
(112,898
)
 
—

 
—

 
(113,059
)
Distributions to noncontrolling interest owners
 
—

 
—

 
—

 
—

 
—

 
—

 
(3,082
)
 
(3,082
)
Contributions
 
—

 
—

 
—

 
—

 
—

 
—

 
23

 
23

Purchase of noncontrolling interest (Note 4)
 
—

 
—

 
—

 
—

 
(6,245
)
 
—

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

 
—

 
—

 
—

 
(741
)
 
—

 
—

 
(741
)
Repurchase of warrants (Note 10)
 
—

 
—

 
—

 
—

 
(10,549
)
 
—

 
—

 
(10,549
)
Equity issued pursuant to incentive compensation plan (Note 10)
 
12

 
—

 
—

 
956,821

 
12,920

 
—

 
—

 
12,932

Common unit repurchases (Note 10)
 
—

 
—

 
—

 
(1,231,189
)
 
(11,663
)
 
—

 
—

 
(11,663
)
Conversion of warrants (Note 10)
 
—

 
—

 
—

 
607,653

 
6

 
—

 
—

 
6

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

 
—

 
—

 
—

 
(7,213
)
 
—

 
—

 
(7,213
)
Issuance of Class B preferred units (Note 10)
 
—

 
8,400,000

 
202,755

 
—

 
—

 
—

 
—

 
202,755

Net (loss) income
 
(194
)
 
—

 
—

 
—

 
(236,539
)
 
—

 
132

 
(236,601
)
Other comprehensive loss
 
—

 
—

 
—

 
—

 
—

 
(434
)
 
—

 
(434
)
BALANCES AT SEPTEMBER 30, 2017
 
$
(50,872
)
 
8,400,000

 
$
202,755

 
120,512,692

 
$
1,819,491

 
$
(2,262
)
 
$
7,181

 
$
1,976,293


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


6

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Unaudited Condensed Consolidated Statements of Cash Flows
(in Thousands)
 
 
Six Months Ended September 30,
 
 
2017
 
2016
OPERATING ACTIVITIES:
 
 
 
 
Net (loss) income
 
$
(237,286
)
 
$
116,095

Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
 
 
 
 
Depreciation and amortization, including amortization of debt issuance costs
 
137,687

 
108,133

Loss (gain) on early extinguishment or revaluation of liabilities, net
 
6,938

 
(30,890
)
Non-cash equity-based compensation expense
 
14,886

 
32,994

Loss (gain) on disposal or impairment of assets, net
 
100,238

 
(203,467
)
Provision for doubtful accounts
 
170

 
(122
)
Net adjustments to fair value of commodity derivatives
 
34,882

 
44,966

Equity in earnings of unconsolidated entities
 
(3,844
)
 
(447
)
Distributions of earnings from unconsolidated entities
 
2,777

 
42

Revaluation of investments
 
—

 
14,365

Other
 
9,399

 
(2,938
)
Changes in operating assets and liabilities, exclusive of acquisitions:
 
 
 
 
Accounts receivable-trade and affiliates
 
(37,903
)
 
(54,069
)
Inventories
 
(18,585
)
 
(151,507
)
Other current and noncurrent assets
 
(24,762
)
 
(44,798
)
Accounts payable-trade and affiliates
 
(27,412
)
 
90,496

Other current and noncurrent liabilities
 
52,769

 
26,270

Net cash provided by (used in) operating activities
 
9,954

 
(54,877
)
INVESTING ACTIVITIES:
 
 
 
 
Capital expenditures
 
(56,468
)
 
(201,633
)
Acquisitions, net of cash acquired
 
(48,434
)
 
(113,297
)
Cash flows from settlements of commodity derivatives
 
(22,039
)
 
(25,015
)
Proceeds from sales of assets
 
24,586

 
396

Proceeds from sale of TLP common units
 
—

 
112,370

Investments in unconsolidated entities
 
(14,150
)
 
—

Distributions of capital from unconsolidated entities
 
4,378

 
5,233

Payments on loan for natural gas liquids facility
 
4,875

 
4,324

Loan to affiliate
 
(960
)
 
(1,700
)
Payments on loan to affiliate
 
—

 
655

Payment to terminate development agreement
 
—

 
(16,875
)
Net cash used in investing activities
 
(108,212
)
 
(235,542
)
FINANCING ACTIVITIES:
 
 
 
 
Proceeds from borrowings under Revolving Credit Facility
 
814,500

 
770,000

Payments on Revolving Credit Facility
 
(657,500
)
 
(595,500
)
Repurchase of senior secured and senior unsecured notes
 
(115,407
)
 
(15,129
)
Payments on other long-term debt
 
(3,163
)
 
(4,423
)
Debt issuance costs
 
(2,474
)
 
(320
)
Contributions from general partner
 
—

 
59

Contributions from noncontrolling interest owners, net
 
23

 
465

Distributions to general and common unit partners and preferred unitholders
 
(107,389
)
 
(83,707
)
Distributions to noncontrolling interest owners
 
(3,082
)
 
(2,750
)
Proceeds from sale of preferred units, net of offering costs
 
202,755

 
235,018

Repurchase of warrants
 
(10,549
)
 
—

Common unit repurchases
 
(11,663
)
 
—

Proceeds from sale of common units, net of offering costs
 
—

 
9,383

Payments for settlement and early extinguishment of liabilities
 
(1,650
)
 
(27,406
)
Other
 
—

 
(20
)
Net cash provided by financing activities
 
104,401

 
285,670

Net increase (decrease) in cash and cash equivalents
 
6,143

 
(4,749
)
Cash and cash equivalents, beginning of period
 
12,264

 
28,176

Cash and cash equivalents, end of period
 
$
18,407

 
$
23,427

Supplemental cash flow information:
 
 
 
 
Cash interest paid
 
$
96,217

 
$
58,869

Income taxes paid (net of income tax refunds)
 
$
1,473

 
$
1,755

Supplemental non-cash investing and financing activities:
 
 
 
 
Distributions declared but not paid to Class B preferred unitholders
 
$
5,670

 
$
—

Accrued capital expenditures
 
$
2,907

 
$
2,073

Value of common units issued in business combinations
 
$
—

 
$
3,969


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

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 September 30, 2017, our operations include:

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

Note 2—Significant Accounting Policies

Basis of Presentation

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

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

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


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 September 30, 2017 and 2016 include $0.3 million and $1.2 million, respectively, and revenues during the six months ended September 30, 2017 and 2016 include $0.7 million and $2.5 million, respectively, associated with the amortization of a liability recorded in the acquisition accounting for an acquired business related to certain out-of-market revenue contracts.

Income Taxes

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

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

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

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 September 30, 2017 or March 31, 2017.

Inventories

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

Inventories consist of the following at the dates indicated:
 
 
September 30, 2017
 
March 31, 2017
 
 
(in thousands)
Crude oil
 
$
81,969

 
$
146,857

Natural gas liquids:
 
 
 
 
Propane
 
107,364

 
38,631

Butane
 
93,257

 
5,992

Other
 
9,389

 
6,035

Refined products:
 
 
 
 
Gasoline
 
131,640

 
193,051

Diesel
 
90,696

 
98,237

Renewables:
 
 
 
 
Ethanol
 
31,273

 
42,009

Biodiesel
 
16,517

 
21,410

Other
 
8,628

 
9,210

Total
 
$
570,733

 
$
561,432


Investments in Unconsolidated Entities

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


11
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Our investments in unconsolidated entities consist of the following at the dates indicated:
Entity
 
Segment
 
Ownership
Interest (1)
 
Date Acquired
or Formed
 
September 30, 2017
 
March 31, 2017
 
 
 
 
 
 
 
 
(in thousands)
Glass Mountain Pipeline, LLC (2)
 
Crude Oil Logistics
 
50%
 
December 2013
 
$
181,982

 
$
172,098

E Energy Adams, LLC
 
Refined Products and Renewables
 
19%
 
December 2013
 
14,264

 
12,952

Water treatment and disposal facility (3)
 
Water Solutions
 
50%
 
August 2015
 
2,035

 
2,147

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

 
226

Total
 
 
 
 
 
 
 
$
198,281

 
$
187,423

 
(1)
Ownership interest percentages are at September 30, 2017.
(2)
Our investment in Glass Mountain Pipeline, LLC (“Glass Mountain”) exceeds our proportionate share of the historical net book value of Glass Mountain’s net assets by $71.5 million at September 30, 2017. This difference relates primarily to goodwill and customer relationships. We amortize the value of the customer relationships and record the expense within equity in earnings of unconsolidated entities in our unaudited condensed consolidated statement of operations.
(3)
This is an investment in an unincorporated joint venture.
(4)
This investment is negative at September 30, 2017 and has been reclassified to current liabilities within our unaudited condensed consolidated balance sheet as we believe the decline to be temporary.

Other Noncurrent Assets

Other noncurrent assets consist of the following at the dates indicated:
 
 
September 30, 2017
 
March 31, 2017
 
 
(in thousands)
Loan receivable (1)
 
$
35,242

 
$
40,684

Line fill (2)
 
30,628

 
30,628

Tank bottoms (3)
 
42,044

 
42,044

Minimum shipping fees - pipeline commitments (4)
 
76,619

 
67,996

Other
 
56,028

 
58,252

Total
 
$
240,561

 
$
239,604

 
(1)
Represents a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party.
(2)
Represents minimum volumes of crude oil we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At September 30, 2017 and March 31, 2017, line fill consisted of 427,193 barrels and 427,193 barrels of crude oil, respectively. Line fill held in pipelines we own is included within property, plant and equipment (see Note 5).
(3)
Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms when the storage tanks are removed from service. At September 30, 2017 and March 31, 2017, tank bottoms held in third party terminals consisted of 366,212 barrels and 366,212 barrels of refined products, respectively. Tank bottoms held in terminals we own are included within property, plant and equipment (see Note 5).
(4)
Represents the minimum shipping fees paid in excess of volumes shipped for two contracts. This amount can be recovered when volumes shipped exceed the minimum monthly volume commitment (see Note 9). Under these contracts, we currently have 2.6 years and 3.0 years, respectively, in which to ship the excess volumes.


12
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following at the dates indicated:
 
 
September 30, 2017
 
March 31, 2017
 
 
(in thousands)
Accrued compensation and benefits
 
$
23,083

 
$
22,227

Excise and other tax liabilities
 
56,562

 
64,051

Derivative liabilities
 
28,942

 
27,622

Accrued interest
 
41,916

 
44,418

Product exchange liabilities
 
25,869

 
1,693

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

 
30,113

Other
 
20,584

 
17,001

Total
 
$
227,069

 
$
207,125


Deferred Gain on Sale of General Partner Interest in TLP

On February 1, 2016, we sold our general partner interest in TransMontaigne Partners L.P. (“TLP”) to an affiliate of ArcLight Capital Partners. We deferred a portion of the gain on the sale and will recognize this amount over our future lease payment obligations, which is approximately seven years. During the three months ended September 30, 2017 and 2016, we recognized $7.5 million and $7.5 million, respectively, and during the six months ended September 30, 2017 and 2016, we recognized $15.1 million and $15.1 million, respectively, of the deferred gain in our unaudited condensed consolidated statements of operations. Within our September 30, 2017 unaudited condensed consolidated balance sheet, the current portion of the deferred gain, $30.1 million, is recorded in accrued expenses and other payables, and the long-term portion, $124.2 million, is recorded in other noncurrent liabilities.

Noncontrolling Interests

Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. Amounts are adjusted by the noncontrolling interest holder’s proportionate share of the subsidiaries’ earnings or losses each period and any distributions that are paid. Noncontrolling interests are reported as a component of equity, unless the noncontrolling interest is considered redeemable, in which case the noncontrolling interest is recorded between liabilities and equity (mezzanine or temporary equity) in our unaudited condensed consolidated balance sheet. The redeemable noncontrolling interest is adjusted at each balance sheet date to its maximum redemption value if the amount is greater than the carrying value. During the six months ended September 30, 2017, we recorded $0.7 million to adjust the redeemable noncontrolling interest to its maximum redemption value.

Business Combination Measurement Period

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

Also, as discussed in Note 4, we made certain adjustments during the six months ended September 30, 2017 to our estimates of the acquisition date fair values of assets acquired and liabilities assumed in business combinations that occurred during the fiscal year ended March 31, 2017.

Reclassifications

We have reclassified certain prior period financial statement information to be consistent with the classification methods used in the current fiscal year. These reclassifications did not impact previously reported amounts of equity, net income, or cash flows. Also, certain line items in our unaudited condensed consolidated statement of cash flows were combined and the prior period amounts were combined to be consistent with the classification methods used in the current fiscal year.

13
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Recent Accounting Pronouncements

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

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

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

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

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


14
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Note 3—(Loss) Income Per Common Unit

The following table presents our calculation of basic and diluted weighted average units outstanding for the periods indicated:
 
Three Months Ended September 30,
 
Six Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Weighted average units outstanding during the period:
 
 
 
 
 
 
 
Common units - Basic
121,314,636

 
106,186,389

 
120,927,400

 
105,183,556

Effect of Dilutive Securities:
 
 
 
 
 
 
 
Performance units
—

 
—

 
—

 
10,557

Warrants
—

 
—

 
—

 
2,803,436

Common units - Diluted
121,314,636

 
106,186,389

 
120,927,400

 
107,997,549


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

Our (loss) income per common unit is as follows for the periods indicated:
 
Three Months Ended September 30,
 
Six Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands, except unit and per unit amounts)
Net (loss) income
$
(173,579
)
 
$
(66,658
)
 
$
(237,286
)
 
$
116,095

Less: Net (income) loss attributable to noncontrolling interests
(80
)
 
59

 
(132
)
 
(5,774
)
Less: Net loss attributable to redeemable noncontrolling interests
288

 
—

 
685

 
—

Net (loss) income attributable to NGL Energy Partners LP
(173,371
)
 
(66,599
)
 
(236,733
)
 
110,321

Less: Distributions to preferred unitholders
(16,098
)
 
(8,668
)
 
(25,782
)
 
(12,052
)
Less: Net loss (income) allocated to general partner (1)
154

 
45

 
194

 
(158
)
Less: Repurchase of warrants (2)
—

 
—

 
(349
)
 
—

Net (loss) income allocated to common unitholders
$
(189,315
)
 
$
(75,222
)
 
$
(262,670
)
 
$
98,111

Basic (loss) income per common unit
$
(1.56
)
 
$
(0.71
)
 
$
(2.17
)
 
$
0.93

Diluted (loss) income per common unit
$
(1.56
)
 
$
(0.71
)
 
$
(2.17
)
 
$
0.91

Basic weighted average common units outstanding
121,314,636

 
106,186,389

 
120,927,400

 
105,183,556

Diluted weighted average common units outstanding
121,314,636

 
106,186,389

 
120,927,400

 
107,997,549

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

Note 4—Acquisitions

The following summarizes our acquisitions during the six months ended September 30, 2017:

Acquisition of Remaining Interest in NGL Solids Solutions, LLC

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

15
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



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

We accounted for the transaction as an acquisition of assets. Acquiring assets in groups requires not only ascertaining the cost of the asset (or net asset) group but also allocating that cost to the individual assets (or individual assets and liabilities) that make up the group. The cost of a group of assets acquired in an asset acquisition is allocated to the individual assets acquired or liabilities assumed/released based on their relative fair values and does not give rise to goodwill or bargain purchase gains. We allocated $22.9 million to noncontrolling interest and $0.2 million to land. The acquisition of the remaining interest was accounted for as an equity transaction, no gain or loss was recorded and the carrying value of the noncontrolling interest was adjusted to reflect the change in ownership interest of the subsidiary. As of the date of the transaction, the 50% noncontrolling interest had a carrying value of $16.6 million. For the termination of the non-compete agreement, we recorded a gain of $1.3 million, which included the carrying value of the non-compete agreement intangible asset that was written off (see Note 7). This gain was recorded within loss (gain) on disposal or impairment of assets, net in our unaudited condensed consolidated statement of operations during the six months ended September 30, 2017.

Retail Propane Businesses

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

We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed for these retail propane businesses, and as a result, the estimates of fair value at September 30, 2017 are subject to change. The following table summarizes the preliminary estimates of the fair values of the assets acquired and liabilities assumed (in thousands):
Current assets
$
1,880

Property, plant and equipment
10,051

Goodwill
4,150

Intangible assets
14,875

Current liabilities
(1,484
)
Other noncurrent liabilities
(134
)
Fair value of net assets acquired
$
29,338


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

The operations of these retail propane businesses have been included in our unaudited condensed consolidated statement of operations since their acquisition date. Our unaudited condensed consolidated statement of operations for the six months ended September 30, 2017 includes revenues of $2.8 million and operating income of less than $0.1 million that were generated by the operations of two of these retail propane businesses. The revenues and operating income of the other retail propane business acquisitions are not considered material.

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

Water Solutions Facilities

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

16
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Retail Propane Businesses

During the six months ended September 30, 2017, we completed the acquisition accounting for three retail propane businesses. During the six months ended September 30, 2017, we received additional information and recorded a decrease of $0.2 million to current assets and a decrease of less than $0.1 million to property, plant and equipment. The offset of these adjustments was recorded to goodwill. In addition, we paid $0.4 million in cash to the sellers during the six months ended September 30, 2017 for consideration that was held back at the acquisition date, which we recorded as a liability within accrued expenses and other payables in our unaudited condensed consolidated balance sheet.

Natural Gas Liquids Facilities

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

Note 5—Property, Plant and Equipment
  
Our property, plant and equipment consists of the following at the dates indicated:
Description
 
Estimated
Useful Lives
 
September 30, 2017
 
March 31, 2017
 
 
 
 
(in thousands)
Natural gas liquids terminal and storage assets
 
2–30 years
 
$
237,468

 
$
207,825

Pipeline and related facilities
 
30–40 years
 
255,894

 
248,582

Refined products terminal assets and equipment
 
15–25 years
 
6,736

 
6,736

Retail propane equipment
 
2–30 years
 
248,971

 
239,417

Vehicles and railcars
 
3–25 years
 
199,661

 
198,480

Water treatment facilities and equipment
 
3–30 years
 
576,765

 
557,100

Crude oil tanks and related equipment
 
2–30 years
 
217,610

 
203,003

Barges and towboats
 
5–30 years
 
91,884

 
91,037

Information technology equipment
 
3–7 years
 
44,531

 
43,880

Buildings and leasehold improvements
 
3–40 years
 
176,877

 
161,957

Land
 
 
 
61,221

 
56,545

Tank bottoms and line fill (1)
 
 
 
25,458

 
24,462

Other
 
3–20 years
 
20,840

 
39,132

Construction in progress
 
 
 
37,389

 
87,711

 
 
 
 
2,201,305

 
2,165,867

Accumulated depreciation
 
 
 
(432,820
)
 
(375,594
)
Net property, plant and equipment
 
 
 
$
1,768,485

 
$
1,790,273

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

The following table summarizes depreciation expense and capitalized interest expense for the periods indicated:
 
 
Three Months Ended September 30,
 
Six Months Ended September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(in thousands)
Depreciation expense
 
$
33,788

 
$
28,703

 
$
66,132

 
$
56,357

Capitalized interest expense
 
$
—

 
$
1,069

 
$
—

 
$
4,804


17
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



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

Note 6—Goodwill

The following table summarizes changes in goodwill by segment during the six months ended September 30, 2017:
 
 
Crude Oil
Logistics
 
Water
Solutions
 
Liquids
 
Retail
Propane
 
Refined
Products and
Renewables
 
Total
 
 
(in thousands)
Balances at March 31, 2017
 
$
579,846

 
$
424,270

 
$
266,046

 
$
130,427

 
$
51,127

 
$
1,451,716

Revisions to acquisition accounting (Note 4)
 
—

 
195

 
—

 
232

 
—

 
427

Acquisitions (Note 4)
 
—

 
—

 
—

 
4,150

 
—

 
4,150

Impairment
 
—

 
—

 
(116,877
)
 
—

 
—

 
(116,877
)
Balances at September 30, 2017
 
$
579,846

 
$
424,465

 
$
149,169

 
$
134,809

 
$
51,127

 
$
1,339,416


Goodwill Impairment

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

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

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


18
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Note 7—Intangible Assets

Our intangible assets consist of the following at the dates indicated:
 
 
 
 
September 30, 2017
 
March 31, 2017
Description
 
Amortizable Lives
 
Gross Carrying
Amount
 
Accumulated
Amortization
 
Net
 
Gross Carrying
Amount
 
Accumulated
Amortization
 
Net
 
 
 
 
(in thousands)
Amortizable:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Customer relationships
 
3–20 years
 
$
906,229

 
$
343,377

 
$
562,852

 
$
906,782

 
$
316,242

 
$
590,540

Customer commitments
 
10 years
 
310,000

 
28,417

 
281,583

 
310,000

 
12,917

 
297,083

Pipeline capacity rights
 
30 years
 
161,785

 
14,349

 
147,436

 
161,785

 
11,652

 
150,133

Rights-of-way and easements
 
1–40 years
 
63,669

 
2,901

 
60,768

 
63,402

 
2,154

 
61,248

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

 
16,433

 
6,664

 
29,036

 
20,457

 
8,579

Non-compete agreements
 
2–32 years
 
18,198

 
5,979

 
12,219

 
32,984

 
17,762

 
15,222

Trade names
 
1–10 years
 
4,074

 
1,736

 
2,338

 
15,439

 
13,396

 
2,043

Debt issuance costs (1)
 
5 years
 
40,790

 
22,265

 
18,525

 
38,983

 
20,025

 
18,958

Total amortizable
 
 
 
1,527,842

 
435,457

 
1,092,385

 
1,558,411

 
414,605

 
1,143,806

Non-amortizable:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trade names
 
 
 
20,150

 
—

 
20,150

 
20,150

 
—

 
20,150

Total non-amortizable
 
 
 
20,150

 
—

 
20,150

 
20,150

 
—

 
20,150

Total
 
 
 
$
1,547,992

 
$
435,457

 
$
1,112,535

 
$
1,578,561

 
$
414,605

 
$
1,163,956

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

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

Write off of Intangible Asset

During the six months ended September 30, 2017, we wrote off $1.8 million related to the non-compete agreement which was terminated as part of our acquisition of the remaining interest in NGL Solids Solutions, LLC (see Note 4).

Amortization expense is as follows for the periods indicated:
 
 
Three Months Ended September 30,
 
Six Months Ended September 30,
Recorded In
 
2017
 
2016
 
2017
 
2016
 
 
(in thousands)
Depreciation and amortization
 
$
31,420

 
$
21,900

 
$
62,955

 
$
43,152

Cost of sales
 
1,506

 
1,749

 
3,091

 
3,345

Interest expense
 
1,154

 
1,731

 
2,240

 
3,456

Total
 
$
34,080

 
$
25,380

 
$
68,286

 
$
49,953



19
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Expected amortization of our intangible assets is as follows (in thousands):
Fiscal Year Ending March 31,
 
2018 (six months)
$
66,729

2019
129,561

2020
126,174

2021
113,067

2022
97,964

Thereafter
558,890

Total
$
1,092,385


Note 8—Long-Term Debt

Our long-term debt consists of the following at the dates indicated:
 
 
September 30, 2017
 
March 31, 2017
 
 
Face
Amount
 
Unamortized
Debt Issuance
Costs (1)
 
Book
Value
 
Face
Amount
 
Unamortized
Debt Issuance
Costs (1)
 
Book
Value
 
 
(in thousands)
Revolving credit facility:
 
 
 
 
 
 
 
 
 
 
 
 
Expansion capital borrowings
 
$
102,000

 
$
—

 
$
102,000

 
$
—

 
$
—

 
$
—

Working capital borrowings
 
869,500

 
—

 
869,500

 
814,500

 
—

 
814,500

Senior secured notes
 
195,000

 
(3,514
)
 
191,486

 
250,000

 
(4,559
)
 
245,441

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

 
(2,342
)
 
358,439

 
379,458

 
(3,191
)
 
376,267

6.875% Notes due 2021
 
367,048

 
(5,131
)
 
361,917

 
367,048

 
(5,812
)
 
361,236

7.500% Notes due 2023
 
673,543

 
(10,166
)
 
663,377

 
700,000

 
(11,329
)
 
688,671

6.125% Notes due 2025
 
484,300

 
(7,941
)
 
476,359

 
500,000

 
(8,567
)
 
491,433

Other long-term debt
 
12,756

 
—

 
12,756

 
15,525

 
—

 
15,525

 
 
3,064,928

 
(29,094
)
 
3,035,834

 
3,026,531

 
(33,458
)
 
2,993,073

Less: Current maturities
 
42,373

 
—

 
42,373

 
29,590

 
—

 
29,590

Long-term debt
 
$
3,022,555

 
$
(29,094
)
 
$
2,993,461

 
$
2,996,941

 
$
(33,458
)
 
$
2,963,483

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

Amortization expense for debt issuance costs related to long-term debt in the table above was $1.6 million and $1.0 million during the three months ended September 30, 2017 and 2016, respectively, and $3.3 million and $1.8 million during the six months ended September 30, 2017 and 2016, respectively.

Expected amortization of debt issuance costs is as follows (in thousands):
Fiscal Year Ending March 31,
 
 
2018 (six months)
 
$
3,034

2019
 
6,061

2020
 
5,135

2021
 
4,754

2022
 
4,173

Thereafter
 
5,937

Total
 
$
29,094



20
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Credit Agreement

We are party to a $1.765 billion credit agreement (the “Credit Agreement”) with a syndicate of banks. As of September 30, 2017, the Credit Agreement includes a revolving credit facility to fund working capital needs, which had a capacity of $1.05 billion for cash borrowings and letters of credit, (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects, which had a capacity of $715.0 million (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). During the three months ended September 30, 2017, we reallocated $50.0 million from the Expansion Capital Facility to the Working Capital Facility. We had letters of credit of $115.1 million on the Working Capital Facility at September 30, 2017.

At September 30, 2017, the borrowings under the Credit Agreement had a weighted average interest rate of 4.50%, calculated as the weighted average LIBOR rate of 1.24% plus a margin of 3.00% for LIBOR borrowings and the prime rate of 4.25% plus a margin of 2.00% on alternate base rate borrowings. At September 30, 2017, the interest rate in effect on letters of credit was 3.00%. Commitment fees were charged at a rate ranging from 0.375% to 0.50% on any unused capacity.

On June 2, 2017, we amended our Credit Agreement. The amendment, among other things, restricts us from increasing our distribution rate over the amount paid in the preceding quarter if our leverage ratio is greater than 4.25 to 1. The following table summarizes the debt covenant levels specified in the Credit Agreement as of September 30, 2017:
 
 
 
 
Senior Secured
 
Interest
Period Beginning
 
Leverage Ratio (1)
 
Leverage Ratio (1)
 
Coverage Ratio (2)
September 30, 2017
 
5.50

 
2.50

 
2.25

March 31, 2018
 
4.75

 
3.25

 
2.75

March 31, 2019 and thereafter
 
4.50

 
3.25

 
2.75

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

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

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

Senior Secured Notes

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

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

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

Senior Unsecured Notes

Registration Rights

In connection with the issuance of the 7.50% senior notes due 2023 (the “2023 Notes”) and the 6.125% senior notes due 2025 (the “2025 Notes”), we entered into a registration rights agreement in which we agreed to file a registration statement

21
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


with the SEC so that the holders can exchange the 2023 Notes and the 2025 Notes for registered notes that have substantially identical terms as the 2023 Notes and the 2025 Notes and evidence the same indebtedness of the 2023 Notes and the 2025 Notes. In addition, the subsidiary guarantors agreed to exchange the guarantee related to the 2023 Notes and the 2025 Notes for a registered guarantee having substantially the same terms as the original guarantee. We filed a registration statement for both the 2023 Notes and the 2025 Notes with the SEC which became effective on July 11, 2017 and 99.98% of the 2023 Notes and 99.98% of the 2025 Notes were exchanged on August 8, 2017.

Repurchases

The following table summarizes repurchases of Senior Unsecured Notes for the periods indicated:
 
 
Three Months Ended
 
Six Months Ended
 
 
September 30,
 
September 30,
 
 
2017
 
2017
 
 
(in thousands)
2019 Notes
 
 
 
 
Notes repurchased
 
$
1,475

 
$
18,677

Cash paid (excluding payments of accrued interest)
 
$
1,449

 
$
18,641

Gain (loss) on early extinguishment of debt (1)
 
$
15

 
$
(102
)
 
 
 
 
 
2023 Notes
 
 
 
 
Notes repurchased
 
$
26,457

 
$
26,457

Cash paid (excluding payments of accrued interest)
 
$
25,459

 
$
25,459

Gain on early extinguishment of debt (2)
 
$
595

 
$
595

 
 
 
 
 
2025 Notes
 
 
 
 
Notes repurchased
 
$
15,700

 
$
15,700

Cash paid (excluding payments of accrued interest)
 
$
14,108

 
$
14,108

Gain on early extinguishment of debt (3)
 
$
1,333

 
$
1,333

 
(1)
Gain (loss) on the early extinguishment of debt for the 2019 Notes during the three months and six months ended September 30, 2017 are net of debt issuance costs of less than $0.1 million and $0.1 million, respectively.
(2)
Gains on the early extinguishment of debt for the 2023 Notes during the three months and six months ended September 30, 2017 are net of debt issuance costs of $0.4 million and $0.4 million, respectively.
(3)
Gains on the early extinguishment of debt for the 2025 Notes during the three months and six months ended September 30, 2017 are net of debt issuance costs of $0.3 million and $0.3 million, respectively.

At September 30, 2017, we were in compliance with the covenants under the indentures for all of the senior unsecured notes.

Other Long-Term Debt

We have executed various non-interest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. These instruments have a principal balance of $6.5 million at September 30, 2017, and the implied interest rates on these instruments range from 1.91% to 7.00% per year. We also have certain notes payable related to equipment financing. These instruments have a principal balance of $6.3 million at September 30, 2017, and the interest rates on these instruments range from 4.13% to 7.10% per year.


22
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at September 30, 2017:
Fiscal Year Ending March 31,
 
Revolving
Credit
Facility
 
Senior Secured Notes
 
Senior Unsecured Notes
 
Other
Long-Term
Debt
 
Total
 
 
(in thousands)
2018 (six months)
 
$
—

 
$
19,500

 
$
—

 
$
1,793

 
$
21,293

2019
 
—

 
39,000

 
—

 
2,895

 
41,895

2020
 
—

 
39,000

 
360,781

 
2,285

 
402,066

2021
 
—

 
39,000

 
—

 
5,450

 
44,450

2022
 
971,500

 
39,000

 
367,048

 
274

 
1,377,822

Thereafter
 
—

 
19,500

 
1,157,843

 
59

 
1,177,402

Total
 
$
971,500

 
$
195,000

 
$
1,885,672

 
$
12,756

 
$
3,064,928


Note 9—Commitments and Contingencies

Legal Contingencies

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

Environmental Matters

Our unaudited condensed consolidated balance sheet at September 30, 2017 includes a liability, measured on an undiscounted basis, of $2.1 million related to environmental matters, which is recorded within accrued expenses and other payables in our unaudited condensed consolidated balance sheet. Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there can be no assurance that we will not incur significant costs. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

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


23
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Asset Retirement Obligations

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

Liabilities incurred
422

Liabilities assumed in acquisitions
21

Liabilities settled
(233
)
Accretion expense
511

Balance at September 30, 2017
$
8,902


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

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment. The following table summarizes future minimum lease payments under these agreements at September 30, 2017 (in thousands):
Fiscal Year Ending March 31,
 
2018 (six months)
$
71,787

2019
120,589

2020
107,255

2021
94,118

2022
65,985

Thereafter
93,844

Total
$
553,578


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

Pipeline Capacity Agreements

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


24
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


The following table summarizes future minimum throughput payments under these agreements at September 30, 2017 (in thousands):
Fiscal Year Ending March 31,
 
2018 (six months)
$
26,001

2019
52,042

2020
42,351

Total
$
120,394


Construction Commitments

At September 30, 2017, we had construction commitments of $24.5 million.

Sales and Purchase Contracts

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

At September 30, 2017, we had the following commodity purchase commitments (in thousands):
 
 
Crude Oil (1)
 
Natural Gas Liquids
 
 
Value
 
Volume
(in barrels)
 
Value
 
Volume
(in gallons)
Fixed-Price Commodity Purchase Commitments:
 
 
 
 
 
 
 
 
2018 (six months)
 
$
161,432

 
3,330

 
$
44,816

 
58,925

2019
 
—

 
—

 
1,340

 
2,268

Total
 
$
161,432

 
3,330

 
$
46,156

 
61,193

 
 
 
 
 
 
 
 
 
Index-Price Commodity Purchase Commitments:
 
 
 
 
 
 
 
 
2018 (six months)
 
$
576,009

 
12,143

 
$
563,817

 
624,075

2019
 
524,256

 
11,595

 
37,426

 
45,736

2020
 
412,569

 
9,324

 
—

 
—

2021
 
161,485

 
3,833

 
—

 
—

2022
 
95,761

 
2,247

 
—

 
—

Total
 
$
1,770,080

 
39,142

 
$
601,243

 
669,811

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


25
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


At September 30, 2017, we had the following commodity sale commitments (in thousands):
 
 
Crude Oil
 
Natural Gas Liquids
 
 
Value
 
Volume
(in barrels)
 
Value
 
Volume
(in gallons)
Fixed-Price Commodity Sale Commitments:
 
 
 
 
 
 
 
 
2018 (six months)
 
$
204,579

 
4,196

 
$
137,467

 
159,427

2019
 
—

 
—

 
7,209

 
9,827

2020
 
—

 
—

 
163

 
215

Total
 
$
204,579

 
4,196

 
$
144,839

 
169,469

 
 
 
 
 
 
 
 
 
Index-Price Commodity Sale Commitments:
 
 
 
 
 
 
 
 
2018 (six months)
 
$
480,203

 
9,507

 
$
522,430

 
478,300

2019
 
94,366

 
1,825

 
6,163

 
6,981

2020
 
54,526

 
1,070

 
—

 
—

Total
 
$
629,095

 
12,402

 
$
528,593

 
485,281


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

Certain other forward purchase and sale contracts do not qualify for the normal purchase and normal sale election. These contracts are recorded at fair value in our unaudited condensed consolidated balance sheet and are not included in the tables above. These contracts are included in the derivative disclosures in Note 11, and represent $28.1 million of our prepaid expenses and other current assets and $28.2 million of our accrued expenses and other payables at September 30, 2017.

Note 10—Equity

Partnership Equity

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

General Partner Contributions

In connection with the issuance of common units for the vesting of restricted units and the warrants that were converted to common units during the six months ended September 30, 2017, we issued 333 notional units to our general partner for less than $0.1 million in order to maintain its 0.1% interest in us.

Common Unit Repurchase Program

On August 29, 2017, the board of directors of our general partner authorized a common unit repurchase program, under which we may repurchase up to $15.0 million of our outstanding common units through December 31, 2017 from time to time in the open market or in other privately negotiated transactions. During the three months ended September 30, 2017, we repurchased 1,193,635 common units for an aggregate price of $11.2 million, including commissions.


26
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Our Distributions

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

 
$
46,870

 
$
80

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

 
$
47,460

 
$
81

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

 
$
47,000

 
$
81


Class A Convertible Preferred Units

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

We allocated the net proceeds on a relative fair value basis to the Class A Preferred Units, which includes the value of a beneficial conversion feature, and the warrants. Accretion for the beneficial conversion feature, recorded as a deemed distribution, was $4.0 million and $2.2 million during the three months ended September 30, 2017 and 2016, respectively, and $7.2 million and $3.8 million during the six months ended September 30, 2017 and 2016, respectively.

The holders of the warrants may convert one-third of the warrants from and after the first anniversary of the original issue date, another one-third of the warrants from and after the second anniversary and the final one-third of the warrants from and after the third anniversary. The warrants have an exercise price of $0.01 and an eight year term. During the six months ended September 30, 2017, 607,653 warrants were converted to common units and we received proceeds of less than $0.1 million. In addition, we repurchased 850,716 unvested warrants for a total purchase price of $10.5 million on June 23, 2017. As of September 30, 2017, we had 2,916,743 warrants outstanding.

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

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

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

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


Class B Preferred Units

During the six months ended September 30, 2017, we issued 8,400,000 of our 9.00% Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”) representing limited partner interests at a price of $25.00 per unit for net proceeds of $202.8 million (net of the underwriters’ discount of $6.6 million and offering costs of $0.6 million).

At any time on or after July 1, 2022, we may redeem our Class B Preferred Units, in whole or in part, at a redemption price of $25.00 per Class B Preferred Unit plus an amount equal to all accumulated and unpaid distributions to, but not including, the date of redemption, whether or not declared. We may also redeem the Class B Preferred Units upon a change of control as defined in our partnership agreement. If we choose not to redeem the Class B Preferred Units, the Class B preferred unitholders may have the ability to convert the Class B Preferred Units to common units at the then applicable conversion rate. Class B preferred unitholders have no voting rights except with respect to certain matters set forth in our partnership agreement.


27
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


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

Amended and Restated Partnership Agreement

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

At-The-Market Program

On August 24, 2016, we entered into an equity distribution agreement in connection with an at-the-market program (the “ATM Program”) pursuant to which we may issue and sell up to $200.0 million of common units. We did not issue any common units under the ATM Program during the six months ended September 30, 2017, and approximately $134.7 million remained available for sale under the ATM Program at September 30, 2017.

Equity-Based Incentive Compensation

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

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

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

The following table summarizes the Service Award activity during the six months ended September 30, 2017:
Unvested Service Award units at March 31, 2017
 
2,708,500

Units granted
 
137,921

Units vested and issued
 
(956,821
)
Units forfeited
 
(51,300
)
Unvested Service Award units at September 30, 2017
 
1,838,300


In connection with the vesting of certain restricted units during the six months ended September 30, 2017, we canceled 37,554 of the newly-vested common units in satisfaction of $0.5 million of employee tax liability paid by us. Pursuant to the terms of the LTIP, these canceled units are available for future grants under the LTIP.


28
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


The following table summarizes the scheduled vesting of our unvested Service Award units at September 30, 2017:
Fiscal Year Ending March 31,
 
 
2018 (six months)
 
—

2019
 
919,350

2020
 
914,450

2021
 
4,500

Total
 
1,838,300


Service Awards are valued at the closing price as of the grant date less the present value of the expected distribution stream over the vesting period using a risk-free interest rate. We record the expense for each Service Award on a straight-line basis over the requisite period for the entire award (that is, over the requisite service period of the last separately vesting portion of the award), ensuring that the amount of compensation cost recognized at any date at least equals the portion of the grant-date value of the award that is vested at that date. During the three months ended September 30, 2017 and 2016, we recorded compensation expense related to Service Award units of $3.3 million and $25.8 million, respectively. During the six months ended September 30, 2017 and 2016, we recorded compensation expense related to Service Award units of $8.6 million and $46.7 million, respectively.

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

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

Fiscal Year Ending March 31,
 
 
2018 (six months)
 
$
5,865

2019
 
10,697

2020
 
2,827

2021
 
13

Total
 
$
19,402


During April 2015, our general partner granted Performance Award units to certain employees. The number of Performance Award units that will vest is contingent on the performance of our common units relative to the performance of the other entities in the Index. Performance will be calculated based on the return on our common units (including changes in the market price of the common units and distributions paid during the performance period) relative to the returns on the common units of the other entities in the Index. As of September 30, 2017, performance will be measured over the following periods:
Vesting Date of Tranche
 
Performance Period for Tranche
July 1, 2018
 
July 1, 2015 through June 30, 2018
July 1, 2019
 
July 1, 2016 through June 30, 2019

The following table summarizes the Performance Award activity during the six months ended September 30, 2017:
Unvested Performance Award units at March 31, 2017
 
1,189,000

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


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


29
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


The fair value of the Performance Awards is estimated using a Monte Carlo simulation at the grant date. We record the expense for each of the tranches of the Performance Awards on a straight-line basis over the period beginning with the grant date and ending with the vesting date of the tranche. Any Performance Awards that do not become earned Performance Awards will terminate, expire and otherwise be forfeited by the participants. During the three months ended September 30, 2017 and 2016, we recorded compensation expense related to Performance Award units of $1.3 million and $1.6 million, respectively. During the six months ended September 30, 2017 and 2016, we recorded compensation expense related to Performance Awards units of $3.4 million and $3.1 million, respectively.

The following table summarizes the estimated future expense we expect to record on the unvested Performance Award units at September 30, 2017 (in thousands):
Fiscal Year Ending March 31,
 
 
2018 (six months)
 
$
2,635

2019
 
3,167

2020
 
642

Total
 
$
6,444


At September 30, 2017, approximately 3.2 million common units remain available for issuance under the LTIP.

Note 11—Fair Value of Financial Instruments

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

Commodity Derivatives

The following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported in our unaudited condensed consolidated balance sheet at the dates indicated:
 
 
September 30, 2017
 
March 31, 2017
 
 
Derivative
Assets
 
Derivative
Liabilities
 
Derivative
Assets
 
Derivative
Liabilities

 
(in thousands)
Level 1 measurements
 
$
17,434

 
$
(39,361
)
 
$
2,590

 
$
(21,113
)
Level 2 measurements
 
29,080

 
(30,511
)
 
38,729

 
(27,799
)

 
46,514

 
(69,872
)
 
41,319

 
(48,912
)
 
 
 
 
 
 
 
 
 
Netting of counterparty contracts (1)
 
(11,127
)
 
11,127

 
(1,508
)
 
1,508

Net cash collateral (held) provided
 
(6,284
)
 
27,774

 
(1,035
)
 
19,604

Commodity derivatives
 
$
29,103

 
$
(30,971
)
 
$
38,776

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


30
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


The following table summarizes the accounts that include our commodity derivative assets and liabilities in our unaudited condensed consolidated balance sheets at the dates indicated:
 
 
September 30, 2017
 
March 31, 2017
 
 
(in thousands)
Prepaid expenses and other current assets
 
$
29,005

 
$
38,711

Other noncurrent assets
 
98

 
65

Accrued expenses and other payables
 
(28,942
)
 
(27,622
)
Other noncurrent liabilities
 
(2,029
)
 
(178
)
Net commodity derivative (liability) asset
 
$
(1,868
)
 
$
10,976


The following table summarizes our open commodity derivative contract positions at the dates indicated. We do not account for these derivatives as hedges.
Contracts
 
Settlement Period
 
Net Long
(Short)
Notional Units
(in barrels)
 
Fair Value
of
Net Assets
(Liabilities)
 
 
 
 
(in thousands)
At September 30, 2017:
 
 
 
 
 
 
Cross-commodity (1)
 
October 2017–March 2018
 
(225
)
 
$
(1,372
)
Crude oil fixed-price (2)
 
October 2017–December 2019
 
(1,442
)
 
(3,005
)
Propane fixed-price (2)
 
October 2017–December 2018
 
498

 
6,165

Refined products fixed-price (2)
 
October 2017–January 2020
 
(1,976
)
 
(18,212
)
Refined products index (2)
 
October 2017–December 2017
 
(6
)
 
(12
)
Other
 
October 2017–March 2022
 
 
 
(6,922
)
 
 
 
 
 
 
(23,358
)
Net cash collateral provided
 
 
 
 
 
21,490

Net commodity derivative liability
 
 
 
 
 
$
(1,868
)
 
 
 
 
 
 
 
At March 31, 2017:
 
 
 
 
 
 
Crude oil fixed-price (2)
 
April 2017–May 2017
 
(800
)
 
$
(55
)
Propane fixed-price (2)
 
April 2017–December 2018
 
220

 
1,082

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

Net commodity derivative asset
 
 
 
 
 
$
10,976

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

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


31
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


Credit Risk

We have credit policies that we believe minimize our overall credit risk, including an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances, and the use of industry standard master netting agreements, which allow for offsetting counterparty receivable and payable balances for certain transactions. At September 30, 2017, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, as the counterparties may be similarly affected by changes in economic, regulatory or other conditions. If a counterparty does not perform on a contract, we may not realize amounts that have been recorded in our unaudited condensed consolidated balance sheets and recognized in our net income.

Interest Rate Risk

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At September 30, 2017, we had $971.5 million of outstanding borrowings under our Revolving Credit Facility at a weighted average interest rate of 4.50%.

Fair Value of Fixed-Rate Notes

The following table provides fair value estimates of our fixed-rate notes at September 30, 2017 (in thousands):
Senior secured notes
$
201,715

Senior unsecured notes:
 
5.125% Notes due 2019
$
360,673

6.875% Notes due 2021
$
366,938

7.500% Notes due 2023
$
670,605

6.125% Notes due 2025
$
451,004


For the senior secured notes, the fair value estimate was developed using observed yields on publicly traded notes issued by us, adjusted for differences in the key terms of those notes and the key terms of our notes (examples include differences in the tenor of the debt, credit standing of the issuer, whether the notes are publicly traded, and whether the notes are secured or unsecured). This fair value estimate would be classified as Level 3 in the fair value hierarchy. For the senior unsecured notes, the fair value estimates were developed based on publicly traded quotes and would be classified as Level 1 in the fair value hierarchy.

Note 12—Segments

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

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

32
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


 
 
Three Months Ended September 30,
 
Six Months Ended September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(in thousands)
Revenues:
 
 
 
 
 
 
 
 
Crude Oil Logistics:
 
 
 
 
 
 
 
 
Crude oil sales
 
$
410,274

 
$
341,981

 
$
890,559

 
$
756,600

Crude oil transportation and other
 
29,315

 
9,172

 
56,301

 
22,106

Elimination of intersegment sales
 
(2,567
)
 
(1,268
)
 
(4,923
)
 
(2,870
)
Total Crude Oil Logistics revenues
 
437,022

 
349,885

 
941,937

 
775,836

Water Solutions:
 
 
 
 
 
 
 
 
Service fees
 
35,282

 
28,528

 
68,603

 
54,225

Recovered hydrocarbons
 
10,446

 
5,681

 
20,406

 
12,877

Other revenues
 
5,304

 
5,524

 
8,990

 
8,384

Total Water Solutions revenues
 
51,032

 
39,733

 
97,999

 
75,486

Liquids:
 
 
 
 
 
 
 
 
Propane sales
 
193,588

 
101,613

 
330,448

 
198,084

Butane sales
 
111,545

 
66,680

 
179,777

 
121,255

Other product sales
 
102,409

 
69,020

 
186,712

 
128,180

Other revenues
 
3,928

 
8,075

 
9,940

 
15,222

Elimination of intersegment sales
 
(18,347
)
 
(11,128
)
 
(35,940
)
 
(23,432
)
Total Liquids revenues
 
393,123

 
234,260

 
670,937

 
439,309

Retail Propane:
 
 
 
 
 
 
 
 
Propane sales
 
48,004

 
36,170

 
96,636

 
77,811

Distillate sales
 
6,676

 
5,589

 
16,231

 
16,044

Other revenues
 
10,043

 
9,331

 
18,936

 
17,638

Elimination of intersegment sales
 
(23
)
 
—

 
(31
)
 
(16
)
Total Retail Propane revenues
 
64,700

 
51,090

 
131,772

 
111,477

Refined Products and Renewables:
 
 
 
 
 
 
 
 
Refined products sales
 
2,874,268

 
2,274,715

 
5,647,875

 
4,151,572

Renewables sales
 
102,964

 
95,830

 
213,930

 
202,312

Service fees
 
50

 
(121
)
 
168

 
11,145

Elimination of intersegment sales
 
(76
)
 
(102
)
 
(130
)
 
(144
)
Total Refined Products and Renewables revenues
 
2,977,206

 
2,370,322

 
5,861,843

 
4,364,885

Corporate and Other
 
246

 
248

 
407

 
515

Total revenues
 
$
3,923,329

 
$
3,045,538

 
$
7,704,895

 
$
5,767,508

Depreciation and Amortization:
 
 
 
 
 
 
 
 
Crude Oil Logistics
 
$
20,958

 
$
9,025

 
$
41,793

 
$
17,993

Water Solutions
 
25,253

 
25,129

 
49,261

 
49,563

Liquids
 
6,141

 
4,425

 
12,471

 
8,874

Retail Propane
 
11,613

 
10,705

 
23,075

 
20,392

Refined Products and Renewables
 
324

 
416

 
648

 
833

Corporate and Other
 
919

 
903

 
1,839

 
1,854

Total depreciation and amortization
 
$
65,208

 
$
50,603

 
$
129,087

 
$
99,509

Operating Income (Loss):
 
 
 
 
 
 
 
 
Crude Oil Logistics
 
$
1,196

 
$
(19,039
)
 
$
5,553

 
$
(19,664
)
Water Solutions
 
(7,548
)
 
(4,430
)
 
(8,702
)
 
75,034

Liquids
 
(118,107
)
 
8,384

 
(126,879
)
 
8,327

Retail Propane
 
(9,226
)
 
(8,717
)
 
(15,094
)
 
(11,219
)
Refined Products and Renewables
 
21,042

 
11,387

 
35,538

 
161,156

Corporate and Other
 
(16,459
)
 
(23,413
)
 
(34,185
)
 
(55,562
)
Total operating (loss) income
 
$
(129,102
)
 
$
(35,828
)
 
$
(143,769
)
 
$
158,072



33
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



The following table summarizes additions to property, plant and equipment and intangible assets by segment for the periods indicated. This information has been prepared on the accrual basis, and includes property, plant and equipment and intangible assets acquired in acquisitions.
 
 
Three Months Ended September 30,
 
Six Months Ended September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(in thousands)
Crude Oil Logistics
 
$
4,663

 
$
32,397

 
$
11,721

 
$
104,702

Water Solutions
 
15,035

 
25,237

 
34,440

 
68,353

Liquids
 
1,138

 
6,693

 
1,680

 
13,161

Retail Propane
 
30,869

 
71,425

 
34,715

 
77,974

Refined Products and Renewables
 
—

 
1,143

 
—

 
1,167

Corporate and Other
 
440

 
614

 
709

 
1,732

Total
 
$
52,145

 
$
137,509

 
$
83,265

 
$
267,089


The following tables summarize long-lived assets (consisting of property, plant and equipment, intangible assets, and goodwill) and total assets by segment at the dates indicated:
 
 
September 30, 2017
 
March 31, 2017
 
 
(in thousands)
Long-lived assets, net:
 
 
 
 
Crude Oil Logistics
 
$
1,677,505

 
$
1,724,805

Water Solutions
 
1,244,035

 
1,261,944

Liquids
 
490,586

 
619,204

Retail Propane
 
561,271

 
547,960

Refined Products and Renewables
 
212,209

 
215,637

Corporate and Other
 
34,830

 
36,395

Total
 
$
4,220,436

 
$
4,405,945

 
 
 
 
 
Total assets:
 
 
 
 
Crude Oil Logistics
 
$
2,377,973

 
$
2,538,768

Water Solutions
 
1,302,896

 
1,301,415

Liquids
 
861,050

 
767,597

Retail Propane
 
630,567

 
622,859

Refined Products and Renewables
 
960,002

 
988,073

Corporate and Other
 
77,170

 
101,667

Total
 
$
6,209,658

 
$
6,320,379


Note 13—Transactions with Affiliates

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

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

Certain members of our management and members of their families as well as other associated parties own interests in entities from which we have purchased products and services and to which we have sold products and services. During the six months ended September 30, 2017, $0.8 million of these transactions were capital expenditures and were recorded as increases to property, plant and equipment.

34
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



The following table summarizes these related party transactions for the periods indicated:
 
 
Three Months Ended September 30,
 
Six Months Ended September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(in thousands)
Sales to SemGroup
 
$
107

 
$
3,513

 
$
230

 
$
3,584

Purchases from SemGroup
 
$
1,911

 
$
1,938

 
$
2,928

 
$
3,963

Sales to equity method investees
 
$
98

 
$
95

 
$
196

 
$
500

Purchases from equity method investees
 
$
20,563

 
$
27,345

 
$
48,469

 
$
57,992

Sales to entities affiliated with management
 
$
57

 
$
75

 
$
140

 
$
152

Purchases from entities affiliated with management
 
$
1,150

 
$
3,493

 
$
1,347

 
$
11,736


Accounts receivable from affiliates consist of the following at the dates indicated:
 
 
September 30, 2017
 
March 31, 2017
 
 
(in thousands)
Receivables from SemGroup
 
$
2,881

 
$
6,668

Receivables from equity method investees
 
17

 
15

Receivables from entities affiliated with management
 
20

 
28

Total
 
$
2,918

 
$
6,711


Accounts payable to affiliates consist of the following at the dates indicated:
 
 
September 30, 2017
 
March 31, 2017
 
 
(in thousands)
Payables to SemGroup
 
$
4,099

 
$
6,571

Payables to equity method investees
 
643

 
1,306

Payables to entities affiliated with management
 
7

 
41

Total
 
$
4,749

 
$
7,918


At September 30, 2017 and March 31, 2017, we had a loan receivable of $4.2 million and $3.2 million, respectively, from Victory Propane, LLC, an equity method investee (see Note 2), with an initial maturity date of March 31, 2021, which can be extended for successive one-year periods unless one of the parties terminates the loan agreement.

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

Note 14—Subsequent Events

On November 7, 2017, we entered into a definitive agreement with DCC LPG, a division of DCC plc, to sell a portion of our Retail Propane business for $200 million in cash, adjusted for working capital at closing. We will retain this business through closing, which is scheduled for March 31, 2018 and will also retain all profits generated through the closing date. The Retail Propane businesses subject to this transaction are comprised of our operations across the Mid-Continent and Western portions of the United States. We will retain our Retail Propane businesses located in the Eastern and Southeastern section of the United States. Closing of the sale is subject to regulatory and other customary closing conditions.


35
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)


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

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

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

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

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

36
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Balance Sheet
(in Thousands)
 
 
September 30, 2017
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
CURRENT ASSETS:
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
6,569

 
$
—

 
$
10,686

 
$
1,152

 
$
—

 
$
18,407

Accounts receivable-trade, net of allowance for doubtful accounts
 
—

 
—

 
838,360

 
3,285

 
—

 
841,645

Accounts receivable-affiliates
 
—

 
—

 
2,918

 
—

 
—

 
2,918

Inventories
 
—

 
—

 
570,017

 
716

 
—

 
570,733

Prepaid expenses and other current assets
 
—

 
—

 
112,120

 
397

 
—

 
112,517

Total current assets
 
6,569

 
—

 
1,534,101

 
5,550

 
—

 
1,546,220

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation
 
—

 
—

 
1,736,522

 
31,963

 
—

 
1,768,485

GOODWILL
 
—

 
—

 
1,326,659

 
12,757

 
—

 
1,339,416

INTANGIBLE ASSETS, net of accumulated amortization
 
—

 
—

 
1,098,906

 
13,629

 
—

 
1,112,535

INVESTMENTS IN UNCONSOLIDATED ENTITIES
 
—

 
—

 
198,281

 
—

 
—

 
198,281

NET INTERCOMPANY RECEIVABLES (PAYABLES)
 
2,477,069

 
—

 
(2,455,724
)
 
(21,345
)
 
—

 
—

INVESTMENTS IN CONSOLIDATED SUBSIDIARIES
 
1,652,951

 
—

 
23,990

 
—

 
(1,676,941
)
 
—

LOAN RECEIVABLE-AFFILIATE
 
—

 
—

 
4,160

 
—

 
—

 
4,160

OTHER NONCURRENT ASSETS
 
—

 
—

 
240,561

 
—

 
—

 
240,561

Total assets
 
$
4,136,589

 
$
—

 
$
3,707,456

 
$
42,554

 
$
(1,676,941
)
 
$
6,209,658

LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
CURRENT LIABILITIES:
 
 
 
 
 
 
 
 
 
 
 
 
Accounts payable-trade
 
$
—

 
$
—

 
$
634,344

 
$
968

 
$
—

 
$
635,312

Accounts payable-affiliates
 
1

 
—

 
4,748

 
—

 
—

 
4,749

Accrued expenses and other payables
 
44,890

 
—

 
181,323

 
856

 
—

 
227,069

Advance payments received from customers
 
—

 
—

 
79,555

 
823

 
—

 
80,378

Current maturities of long-term debt
 
39,000

 
—

 
2,993

 
380

 
—

 
42,373

Total current liabilities
 
83,891

 
—

 
902,963

 
3,027

 
—

 
989,881

LONG-TERM DEBT, net of debt issuance costs and current maturities
 
2,012,578

 
—

 
979,965

 
918

 
—

 
2,993,461

OTHER NONCURRENT LIABILITIES
 
—

 
—

 
171,576

 
4,309

 
—

 
175,885

CLASS A 10.75% CONVERTIBLE PREFERRED UNITS
 
71,009

 
—

 
—

 
—

 
—

 
71,009

REDEEMABLE NONCONTROLLING INTEREST
 
—

 
—

 
—

 
3,129

 
—

 
3,129

EQUITY:
 
 
 
 
 
 
 
 
 
 
 
 
Partners’ equity
 
1,969,111

 
—

 
1,654,991

 
31,394

 
(1,684,122
)
 
1,971,374

Accumulated other comprehensive loss
 
—

 
—

 
(2,039
)
 
(223
)
 
—

 
(2,262
)
Noncontrolling interests
 
—

 
—

 
—

 
—

 
7,181

 
7,181

Total equity
 
1,969,111

 
—

 
1,652,952

 
31,171

 
(1,676,941
)
 
1,976,293

Total liabilities and equity
 
$
4,136,589

 
$
—

 
$
3,707,456

 
$
42,554

 
$
(1,676,941
)
 
$
6,209,658


37
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



38
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Statement of Operations
(in Thousands)
 
 
Three Months Ended September 30, 2017
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
 
 
REVENUES
 
$
—

 
$
—

 
$
3,918,880

 
$
5,356

 
$
(907
)
 
$
3,923,329

COST OF SALES
 
—

 
—

 
3,768,306

 
3,322

 
(907
)
 
3,770,721

OPERATING COSTS AND EXPENSES:
 
 
 
 
 
 
 
 
 
 
 
 
Operating
 
—

 
—

 
74,404

 
1,566

 
—

 
75,970

General and administrative
 
—

 
—

 
23,353

 
127

 
—

 
23,480

Depreciation and amortization
 
—

 
—

 
64,499

 
709

 
—

 
65,208

Loss on disposal or impairment of assets, net
 
—

 
—

 
110,952

 
500

 
—

 
111,452

Revaluation of liabilities
 
—

 
—

 
5,600

 
—

 
—

 
5,600

Operating Loss
 
—

 
—

 
(128,234
)
 
(868
)
 
—

 
(129,102
)
OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
 
 
 
 
 
Equity in earnings of unconsolidated entities
 
—

 
—

 
2,028

 
—

 
—

 
2,028

Interest expense
 
(37,219
)
 
—

 
(12,992
)
 
(227
)
 
205

 
(50,233
)
Gain on early extinguishment of liabilities, net
 
1,943

 
—

 
—

 
—

 
—

 
1,943

Other income, net
 
—

 
—

 
2,084

 
17

 
(205
)
 
1,896

Loss Before Income Taxes
 
(35,276
)
 
—

 
(137,114
)
 
(1,078
)
 
—

 
(173,468
)
INCOME TAX EXPENSE
 
—

 
—

 
(111
)
 
—

 
—

 
(111
)
EQUITY IN NET LOSS OF CONSOLIDATED SUBSIDIARIES
 
(138,095
)
 
—

 
(870
)
 
—

 
138,965

 
—

Net Loss
 
(173,371
)
 
—

 
(138,095
)
 
(1,078
)
 
138,965

 
(173,579
)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
 
 
 
 
 
 
 
 
(80
)
 
(80
)
LESS: NET LOSS ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS
 
 
 
 
 
 
 
 
 
288

 
288

LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS
 
 
 
 
 
 
 
 
 
(16,098
)
 
(16,098
)
LESS: NET LOSS ALLOCATED TO GENERAL PARTNER
 
 
 
 
 
 
 
 
 
154

 
154

NET LOSS ALLOCATED TO COMMON UNITHOLDERS
 
$
(173,371
)
 
$
—

 
$
(138,095
)
 
$
(1,078
)
 
$
123,229

 
$
(189,315
)

39
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Statement of Operations
(in Thousands)
 
 
Three Months Ended September 30, 2016
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
 
 
REVENUES
 
$
—

 
$
—

 
$
3,034,053

 
$
12,118

 
$
(633
)
 
$
3,045,538

COST OF SALES
 
—

 
—

 
2,928,036

 
1,327

 
(633
)
 
2,928,730

OPERATING COSTS AND EXPENSES:
 
 
 
 
 
 
 
 
 
 
 
 
Operating
 
—

 
—

 
68,750

 
4,505

 
—

 
73,255

General and administrative
 
—

 
—

 
27,686

 
240

 
—

 
27,926

Depreciation and amortization
 
—

 
—

 
47,740

 
2,863

 
—

 
50,603

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

 
—

 
896

 
(44
)
 
—

 
852

Operating (Loss) Income
 
—

 
—

 
(39,055
)
 
3,227

 
—

 
(35,828
)
OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
 
 
 
 
 
Equity in earnings of unconsolidated entities
 
—

 
—

 
53

 
—

 
—

 
53

Interest expense
 
(16,364
)
 
—

 
(16,870
)
 
(291
)
 
83

 
(33,442
)
Gain on early extinguishment of liabilities, net
 
—

 
—

 
938

 
—

 
—

 
938

Other income, net
 
—

 
—

 
2,154

 
10

 
(83
)
 
2,081

(Loss) Income Before Income Taxes
 
(16,364
)
 
—

 
(52,780
)
 
2,946

 
—

 
(66,198
)
INCOME TAX EXPENSE
 
—

 
—

 
(460
)
 
—

 
—

 
(460
)
EQUITY IN NET (LOSS) INCOME OF CONSOLIDATED SUBSIDIARIES
 
(50,235
)
 
—

 
3,005

 
—

 
47,230

 
—

Net (Loss) Income
 
(66,599
)
 
—

 
(50,235
)
 
2,946

 
47,230

 
(66,658
)
LESS: NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
 
 
 
 
 
 
 
 
59

 
59

LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS
 
 
 
 
 
 
 
 
 
(8,668
)
 
(8,668
)
LESS: NET LOSS ALLOCATED TO GENERAL PARTNER
 
 
 
 
 
 
 
 
 
45

 
45

NET (LOSS) INCOME ALLOCATED TO COMMON UNITHOLDERS
 
$
(66,599
)
 
$
—

 
$
(50,235
)
 
$
2,946

 
$
38,666

 
$
(75,222
)

40
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Statement of Operations
(in Thousands)
 
 
Six Months Ended September 30, 2017
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
 
 
REVENUES
 
$
—

 
$
—

 
$
7,696,763

 
$
9,443

 
$
(1,311
)
 
$
7,704,895

COST OF SALES
 
—

 
—

 
7,409,800

 
4,340

 
(1,311
)
 
7,412,829

OPERATING COSTS AND EXPENSES:
 
 

 
 

 
 

 
 

 
 

 
 

Operating
 
—

 
—

 
148,908

 
3,531

 
—

 
152,439

General and administrative
 
—

 
—

 
48,157

 
314

 
—

 
48,471

Depreciation and amortization
 
—

 
—

 
126,932

 
2,155

 
—

 
129,087

Loss on disposal or impairment of assets, net
 
—

 
—

 
99,073

 
1,165

 
—

 
100,238

Revaluation of liabilities
 
—

 
—

 
5,600

 
—

 
—

 
5,600

Operating Loss
 
—

 
—

 
(141,707
)
 
(2,062
)
 
—

 
(143,769
)
OTHER INCOME (EXPENSE):
 
 

 
 

 
 

 
 

 
 

 
 

Equity in earnings of unconsolidated entities
 
—

 
—

 
3,844

 
—

 
—

 
3,844

Interest expense
 
(75,590
)
 
—

 
(23,824
)
 
(453
)
 
408

 
(99,459
)
Loss on early extinguishment of liabilities, net
 
(1,338
)
 
—

 
—

 
—

 
—

 
(1,338
)
Other income, net
 
—

 
—

 
4,358

 
56

 
(408
)
 
4,006

Loss Before Income Taxes
 
(76,928
)
 
—

 
(157,329
)
 
(2,459
)
 
—

 
(236,716
)
INCOME TAX EXPENSE
 
—

 
—

 
(570
)
 
—

 
—

 
(570
)
EQUITY IN NET LOSS OF CONSOLIDATED SUBSIDIARIES
 
(159,805
)
 
—

 
(1,906
)
 
—

 
161,711

 
—

Net Loss
 
(236,733
)
 
—

 
(159,805
)
 
(2,459
)
 
161,711

 
(237,286
)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
 

 
 

 
 

 
 

 
(132
)
 
(132
)
LESS: NET LOSS ATTRIBUTABLE TO REDEEMABLE NONCONTROLLING INTERESTS
 
 
 
 
 
 
 
 
 
685

 
685

LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS
 
 
 
 
 
 
 
 
 
(25,782
)
 
(25,782
)
LESS: NET LOSS ALLOCATED TO GENERAL PARTNER
 
 
 
 
 
 
 
 
 
194

 
194

LESS: REPURCHASE OF WARRANTS
 
 
 
 
 
 
 
 
 
(349
)
 
(349
)
NET LOSS ALLOCATED TO COMMON UNITHOLDERS
 
$
(236,733
)
 
$
—

 
$
(159,805
)
 
$
(2,459
)
 
$
136,327

 
$
(262,670
)


41
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Statement of Operations
(in Thousands)
 
 
Six Months Ended September 30, 2016
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
 
 
REVENUES
 
$
—

 
$
—

 
$
5,749,034

 
$
19,469

 
$
(995
)
 
$
5,767,508

COST OF SALES
 
—

 
—

 
5,493,864

 
2,301

 
(995
)
 
5,495,170

OPERATING COSTS AND EXPENSES:
 
 

 
 

 
 

 
 

 
 

 
 

Operating
 
—

 
—

 
139,631

 
8,796

 
—

 
148,427

General and administrative
 
—

 
—

 
69,312

 
485

 
—

 
69,797

Depreciation and amortization
 
—

 
—

 
94,049

 
5,460

 
—

 
99,509

Gain on disposal or impairment of assets, net
 
—

 
—

 
(203,443
)
 
(24
)
 
—

 
(203,467
)
Operating Income
 
—

 
—

 
155,621

 
2,451

 
—

 
158,072

OTHER INCOME (EXPENSE):
 
 

 
 

 
 

 
 

 
 

 
 

Equity in earnings of unconsolidated entities
 
—

 
—

 
447

 
—

 
—

 
447

Revaluation of investments
 
—

 
—

 
(14,365
)
 
—

 
—

 
(14,365
)
Interest expense
 
(32,690
)
 
—

 
(30,898
)
 
(453
)
 
161

 
(63,880
)
Gain on early extinguishment of liabilities, net
 
8,614

 
—

 
22,276

 
—

 
—

 
30,890

Other income, net
 
—

 
—

 
5,990

 
24

 
(161
)
 
5,853

(Loss) Income Before Income Taxes
 
(24,076
)
 
—

 
139,071

 
2,022

 
—

 
117,017

INCOME TAX EXPENSE
 
—

 
—

 
(922
)
 
—

 
—

 
(922
)
EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES
 
134,397

 
—

 
(3,752
)
 
—

 
(130,645
)
 
—

Net Income
 
110,321

 
—

 
134,397

 
2,022

 
(130,645
)
 
116,095

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
 
 
 
 
 
 
 
 
(5,774
)
 
(5,774
)
LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS
 
 
 
 
 
 
 
 
 
(12,052
)
 
(12,052
)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER
 
 

 
 

 
 

 
 

 
(158
)
 
(158
)
NET INCOME ALLOCATED TO COMMON UNITHOLDERS
 
$
110,321

 
$
—

 
$
134,397

 
$
2,022

 
$
(148,629
)
 
$
98,111


42
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Statements of Comprehensive Income (Loss)
(in Thousands)
 
 
Three Months Ended September 30, 2017
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
Net loss
 
$
(173,371
)
 
$
—

 
$
(138,095
)
 
$
(1,078
)
 
$
138,965

 
$
(173,579
)
Other comprehensive loss
 
—

 
—

 
(48
)
 
(11
)
 
—

 
(59
)
Comprehensive loss
 
$
(173,371
)
 
$
—

 
$
(138,143
)
 
$
(1,089
)
 
$
138,965

 
$
(173,638
)

 
 
Three Months Ended September 30, 2016
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
Net (loss) income
 
$
(66,599
)
 
$
—

 
$
(50,235
)
 
$
2,946

 
$
47,230

 
$
(66,658
)
Other comprehensive loss
 
—

 
—

 
(333
)
 
—

 
—

 
(333
)
Comprehensive (loss) income
 
$
(66,599
)
 
$
—

 
$
(50,568
)
 
$
2,946

 
$
47,230

 
$
(66,991
)

 
 
Six Months Ended September 30, 2017
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
Net loss
 
$
(236,733
)
 
$
—

 
$
(159,805
)
 
$
(2,459
)
 
$
161,711

 
$
(237,286
)
Other comprehensive loss
 
—

 
—

 
(412
)
 
(22
)
 
—

 
(434
)
Comprehensive loss
 
$
(236,733
)
 
$
—

 
$
(160,217
)
 
$
(2,481
)
 
$
161,711

 
$
(237,720
)

 
 
Six Months Ended September 30, 2016
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
Net income
 
$
110,321

 
$
—

 
$
134,397

 
$
2,022

 
$
(130,645
)
 
$
116,095

Other comprehensive loss
 
—

 
—

 
(475
)
 
(10
)
 
—

 
(485
)
Comprehensive income
 
$
110,321

 
$
—

 
$
133,922

 
$
2,012

 
$
(130,645
)
 
$
115,610



43
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Statement of Cash Flows
(in Thousands)
 
 
Six Months Ended September 30, 2017
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidated
OPERATING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
 
$
43,235

 
$
—

 
$
(67,691
)
 
$
34,410

 
$
9,954

INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Capital expenditures
 
—

 
—

 
(55,666
)
 
(802
)
 
(56,468
)
Acquisitions, net of cash acquired
 
—

 
—

 
(48,034
)
 
(400
)
 
(48,434
)
Cash flows from settlements of commodity derivatives
 
—

 
—

 
(22,039
)
 
—

 
(22,039
)
Proceeds from sales of assets
 
—

 
—

 
24,586

 
—

 
24,586

Investments in unconsolidated entities
 
—

 
—

 
(14,150
)
 
—

 
(14,150
)
Distributions of capital from unconsolidated entities
 
—

 
—

 
4,378

 
—

 
4,378

Payments on loan for natural gas liquids facility
 
—

 
—

 
4,875

 
—

 
4,875

Loan to affiliate
 
—

 
—

 
(960
)
 
—

 
(960
)
Net cash used in investing activities
 
—

 
—

 
(107,010
)
 
(1,202
)
 
(108,212
)
FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Proceeds from borrowings under Revolving Credit Facility
 
—

 
—

 
814,500

 
—

 
814,500

Payments on Revolving Credit Facility
 
—

 
—

 
(657,500
)
 
—

 
(657,500
)
Repurchase of senior secured and senior unsecured notes
 
(115,407
)
 
—

 
—

 
—

 
(115,407
)
Payments on other long-term debt
 
—

 
—

 
(2,973
)
 
(190
)
 
(3,163
)
Debt issuance costs
 
(670
)
 
—

 
(1,804
)
 
—

 
(2,474
)
Contributions from noncontrolling interest owners, net
 
—

 
—

 
—

 
23

 
23

Distributions to general and common unit partners and preferred unitholders
 
(107,389
)
 
—

 
—

 
—

 
(107,389
)
Distributions to noncontrolling interest owners
 
—

 
—

 
—

 
(3,082
)
 
(3,082
)
Proceeds from sale of preferred units, net of offering costs
 
202,755

 
—

 
—

 
—

 
202,755

Repurchase of warrants
 
(10,549
)
 
—

 
—

 
—

 
(10,549
)
Common unit repurchases
 
(11,663
)
 
—

 
—

 
—

 
(11,663
)
Payments for settlement and early extinguishment of liabilities
 
—

 
—

 
(1,650
)
 
—

 
(1,650
)
Net changes in advances with consolidated entities
 
—

 
—

 
31,911

 
(31,911
)
 
—

Net cash (used in) provided by financing activities
 
(42,923
)
 
—

 
182,484

 
(35,160
)
 
104,401

Net increase (decrease) in cash and cash equivalents
 
312

 
—

 
7,783

 
(1,952
)
 
6,143

Cash and cash equivalents, beginning of period
 
6,257

 
—

 
2,903

 
3,104

 
12,264

Cash and cash equivalents, end of period
 
$
6,569

 
$
—

 
$
10,686

 
$
1,152

 
$
18,407


44
NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements (Continued)



Unaudited Condensed Consolidating Statement of Cash Flows
(in Thousands)
 
 
Six Months Ended September 30, 2016
 
 
NGL Energy
Partners LP
(Parent)
 
NGL Energy
Finance Corp.
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidated
OPERATING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Net cash used in operating activities
 
$
(31,541
)
 
$
—

 
$
(11,229
)
 
$
(12,107
)
 
$
(54,877
)
INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Capital expenditures
 
—

 
—

 
(200,286
)
 
(1,347
)
 
(201,633
)
Acquisitions, net of cash acquired
 
—

 
—

 
(113,297
)
 
—

 
(113,297
)
Cash flows from settlements of commodity derivatives
 
—

 
—

 
(25,015
)
 
—

 
(25,015
)
Proceeds from sales of assets
 
—

 
—

 
379

 
17

 
396

Proceeds from sale of TLP common units
 
—

 
—

 
112,370

 
—

 
112,370

Distributions of capital from unconsolidated entities
 
—

 
—

 
5,233

 
—

 
5,233

Payments on loan for natural gas liquids facility
 
—

 
—

 
4,324

 
—

 
4,324

Loan to affiliate
 
—

 
—

 
(1,700
)
 
—

 
(1,700
)
Payments on loan to affiliate
 
—

 
—

 
655

 
—

 
655

Payment to terminate development agreement
 
—

 
—

 
(16,875
)
 
—

 
(16,875
)
Net cash used in investing activities
 
—

 
—

 
(234,212
)
 
(1,330
)
 
(235,542
)
FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Proceeds from borrowings under Revolving Credit Facility
 
—

 
—

 
770,000

 
—

 
770,000

Payments on Revolving Credit Facility
 
—

 
—

 
(595,500
)
 
—

 
(595,500
)
Repurchase of senior unsecured notes
 
(15,129
)
 
—

 
—

 
—

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

 
—

 
(4,080
)
 
(343
)
 
(4,423
)
Debt issuance costs
 
(255
)
 
—

 
(65
)
 
—

 
(320
)
Contributions from general partner
 
59

 
—

 
—

 
—

 
59

Contributions from noncontrolling interest owners, net
 
(501
)
 
—

 
—

 
966

 
465

Distributions to general and common unit partners and preferred unitholders
 
(83,707
)
 
—

 
—

 
—

 
(83,707
)
Distributions to noncontrolling interest owners
 
—

 
—

 
—

 
(2,750
)
 
(2,750
)
Proceeds from sale of preferred units, net of offering costs
 
235,018

 
—

 
—

 
—

 
235,018

Proceeds from sale of common units, net of offering costs
 
9,383

 
—

 
—

 
—

 
9,383

Payments for settlement and early extinguishment of liabilities
 
—

 
—

 
(27,406
)
 
—

 
(27,406
)
Net changes in advances with consolidated entities
 
(128,960
)
 
—

 
113,907

 
15,053

 
—

Other
 
—

 
—

 
(20
)
 
—

 
(20
)
Net cash provided by financing activities
 
15,908

 
—

 
256,836

 
12,926

 
285,670

Net (decrease) increase in cash and cash equivalents
 
(15,633
)
 
—

 
11,395

 
(511
)
 
(4,749
)
Cash and cash equivalents, beginning of period
 
25,749

 
—

 
784

 
1,643

 
28,176

Cash and cash equivalents, end of period
 
$
10,116

 
$
—

 
$
12,179

 
$
1,132

 
$
23,427



45

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

The following is a discussion of NGL Energy Partners LP’s (“we,” “us,” “our,” or the “Partnership”) financial condition and results of operations as of and for the three months and six months ended September 30, 2017. The discussion should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q (“Quarterly Report”), as well as Management’s Discussion and Analysis of Financial Condition and Results of Operations and the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2017 (“Annual Report”) filed with the Securities and Exchange Commission on May 26, 2017.

Overview

We are a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At September 30, 2017, our operations include:

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


46

Consolidated Results of Operations

The following table summarizes our unaudited condensed consolidated statements of operations for the periods indicated:
 
Three Months Ended September 30,
 
Six Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Total revenues
$
3,923,329

 
$
3,045,538

 
$
7,704,895

 
$
5,767,508

Total cost of sales
3,770,721

 
2,928,730

 
7,412,829

 
5,495,170

Operating expenses
75,970

 
73,255

 
152,439

 
148,427

General and administrative expense
23,480

 
27,926

 
48,471

 
69,797

Depreciation and amortization
65,208

 
50,603

 
129,087

 
99,509

Loss (gain) on disposal or impairment of assets, net
111,452

 
852

 
100,238

 
(203,467
)
Revaluation of liabilities
5,600

 
—

 
5,600

 
—

Operating (loss) income
(129,102
)
 
(35,828
)
 
(143,769
)
 
158,072

Equity in earnings of unconsolidated entities
2,028

 
53

 
3,844

 
447

Revaluation of investments
—

 
—

 
—

 
(14,365
)
Interest expense
(50,233
)
 
(33,442
)
 
(99,459
)
 
(63,880
)
Gain (loss) on early extinguishment of liabilities, net
1,943

 
938

 
(1,338
)
 
30,890

Other income, net
1,896

 
2,081

 
4,006

 
5,853

(Loss) income before income taxes
(173,468
)
 
(66,198
)
 
(236,716
)
 
117,017

Income tax expense
(111
)
 
(460
)
 
(570
)
 
(922
)
Net (loss) income
(173,579
)
 
(66,658
)
 
(237,286
)
 
116,095

Less: Net (income) loss attributable to noncontrolling interests
(80
)
 
59

 
(132
)
 
(5,774
)
Less: Net loss attributable to redeemable noncontrolling interests
288

 
—

 
685

 
—

Net (loss) income attributable to NGL Energy Partners LP
(173,371
)
 
(66,599
)
 
(236,733
)
 
110,321

Less: Distributions to preferred unitholders
(16,098
)
 
(8,668
)
 
(25,782
)
 
(12,052
)
Less: Net loss (income) allocated to general partner
154

 
45

 
194

 
(158
)
Less: Repurchase of warrants
—

 
—

 
(349
)
 
—

Net (loss) income allocated to common unitholders
$
(189,315
)
 
$
(75,222
)
 
$
(262,670
)
 
$
98,111


Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations, disposals and other transactions. Our results of operations for the three months and six months ended September 30, 2017 are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2018. See the detailed discussion of items affecting operating income (loss) by segment below.

Recent Developments

Senior Secured Notes

On August 2, 2017, we amended the note purchase agreement for our senior secured notes with an effective date of June 2, 2017. The amendment, among other things, conforms the financial covenants to match the amended terms of the Credit Agreement (as defined herein), provides for an increase in interest charged if our leverage ratio exceeds certain predetermined levels and restricts us from increasing our distribution rate. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further description.


47

Repurchases of Senior Unsecured Notes

During the three months ended September 30, 2017, we repurchased $1.5 million of the 5.125% senior notes due 2019 (the “2019 Notes”), $26.5 million of the 7.50% senior notes due 2023 (the “2023 Notes”), and $15.7 million of the 6.125% senior notes due 2025 (the “2025 Notes”). See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Common Unit Repurchase Program

On August 29, 2017, the board of directors of our general partner authorized a common unit repurchase program, under which we may repurchase up to $15.0 million of our outstanding common units through December 31, 2017 from time to time in the open market or in other privately negotiated transactions. During the three months ended September 30, 2017, we repurchased 1,193,635 common units for an aggregate price of $11.2 million, including commissions.

Acquisitions

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

During the six months ended September 30, 2017, in our Water Solutions segment, we acquired the remaining 50% ownership interest in NGL Solids Solutions, LLC, and in our Retail Propane segment, we acquired four retail propane businesses. See Note 4 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

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

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



48

Segment Operating Results for the Three Months Ended September 30, 2017 and 2016

Crude Oil Logistics

The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated:
 
 
Three Months Ended September 30,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per barrel amounts)
Revenues:
 
 
 
 
 
 
Crude oil sales
 
$
410,274

 
$
341,981

 
$
68,293

Crude oil transportation and other
 
29,315

 
9,172

 
20,143

Total revenues (1)
 
439,589

 
351,153

 
88,436

Expenses:
 
 

 
 

 
 

Cost of sales
 
403,737

 
341,786

 
61,951

Operating expenses
 
12,198

 
9,708

 
2,490

General and administrative expenses
 
1,657

 
1,196

 
461

Depreciation and amortization expense
 
20,958

 
9,025

 
11,933

(Gain) loss on disposal or impairment of assets, net
 
(157
)
 
8,477

 
(8,634
)
Total expenses
 
438,393

 
370,192

 
68,201

Segment operating income (loss)
 
$
1,196

 
$
(19,039
)
 
$
20,235

 
 
 
 
 
 
 
Crude oil sold (barrels)
 
8,562

 
7,770

 
792

Crude oil transported on owned pipelines (barrels)
 
8,182

 
—

 
8,182

Crude oil storage capacity - owned and leased (barrels) (2)
 
6,159

 
6,355

 
(196
)
Crude oil storage capacity sub-leased to third parties (barrels) (2)
 
700

 
2,000

 
(1,300
)
Crude oil inventory (barrels) (2)
 
1,682

 
1,982

 
(300
)
Crude oil sold ($/barrel)
 
$
47.918

 
$
44.013

 
$
3.905

Cost per crude oil sold ($/barrel)
 
$
47.155

 
$
43.988

 
$
3.167

Crude oil product margin ($/barrel)
 
$
0.763

 
$
0.025

 
$
0.738

 
(1)
Revenues include $2.6 million and $1.3 million of intersegment sales during the three months ended September 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.
(2)
Information is presented as of September 30, 2017 and September 30, 2016, respectively.

Crude Oil Sales. The increase was due primarily to an increase in crude oil prices and barrels sold during the three months ended September 30, 2017, compared to the three months ended September 30, 2016. This segment continued to be impacted by competition and low margins in the majority of the basins across the United States and we continue to market crude volumes in this lower price environment to support our various pipeline, terminal and transportation assets.

Crude Oil Transportation and Other Revenues. The increase was due primarily to our Grand Mesa Pipeline becoming operational on November 1, 2016 with revenues of $19.1 million and higher revenues in our trucking and barge operations during the three months ended September 30, 2017, due to an increase in demand for transportation services, compared to the three months ended September 30, 2016, partially offset by the flattening of the contango curve for crude oil (a condition in which forward crude oil prices are greater than spot prices) during the three months ended September 30, 2017, compared to the three months ended September 30, 2016.

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


49

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

Depreciation and Amortization Expense. The increase was due primarily to our Grand Mesa Pipeline project becoming operational on November 1, 2016. During the three months ended September 30, 2017, we incurred depreciation and amortization expense of $10.6 million related to Grand Mesa. Also contributing to the increase was higher depreciation expense related to other capital projects being placed into service.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the three months ended September 30, 2017, we recorded a net gain of $0.2 million on the sales of excess pipe and certain other assets. During the three months ended September 30, 2016, we recorded a net loss of $4.8 million on the sales of certain assets and a loss of $3.7 million due to the write-down of certain other assets.

Water Solutions

The following table summarizes the operating results of our Water Solutions segment for the periods indicated:
 
 
Three Months Ended September 30,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per barrel and per day amounts)
Revenues:
 
 
 
 
 
 
Service fees
 
$
35,282

 
$
28,528

 
$
6,754

Recovered hydrocarbons
 
10,446

 
5,681

 
4,765

Other revenues
 
5,304

 
5,524

 
(220
)
Total revenues
 
51,032

 
39,733

 
11,299

Expenses:
 
 
 
 
 
 
Cost of sales-derivative loss (gain)
 
2,240

 
(2,354
)
 
4,594

Cost of sales-other
 
434

 
547

 
(113
)
Operating expenses
 
23,488

 
20,227

 
3,261

General and administrative expenses
 
650

 
625

 
25

Depreciation and amortization expense
 
25,253

 
25,129

 
124

Loss (gain) on disposal or impairment of assets, net
 
915

 
(11
)
 
926

Revaluation of liabilities
 
5,600

 
—

 
5,600

Total expenses
 
58,580

 
44,163

 
14,417

Segment operating loss
 
$
(7,548
)
 
$
(4,430
)
 
$
(3,118
)
 
 
 
 
 
 
 
Wastewater processed (barrels per day)
 
 
 
 
 
 
Eagle Ford Basin
 
209,792

 
201,390

 
8,402

Permian Basin
 
273,290

 
201,149

 
72,141

DJ Basin
 
108,952

 
62,641

 
46,311

Other Basins
 
63,443

 
37,559

 
25,884

Total
 
655,477

 
502,739

 
152,738

Solids processed (barrels per day)
 
5,794

 
2,541

 
3,253

Skim oil sold (barrels per day)
 
2,618

 
1,549

 
1,069

Service fees for wastewater processed ($/barrel)
 
$
0.59

 
$
0.62

 
$
(0.03
)
Recovered hydrocarbons for wastewater processed ($/barrel)
 
$
0.17

 
$
0.12

 
$
0.05

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

 
$
0.44

 
$
(0.05
)

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

50


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

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

Cost of Sales-Derivatives. We enter into derivatives in our Water Solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expect to recover when processing the wastewater and selling the skim oil. Our cost of sales during the three months ended September 30, 2017 included $0.8 million of net realized gains on derivatives and $3.0 million of net unrealized losses on derivatives. Our cost of sales during the three months ended September 30, 2016 included $2.2 million of net unrealized gains on derivatives and $0.2 million of net realized gains on derivatives.

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

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

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

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

Revaluation of Liabilities. The revaluation of liabilities represents the change in the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations during the fiscal year ended March 31, 2017. The increase in the expense during the three months ended September 30, 2017 was due primarily to higher actual and expected production from new customers, resulting in an increase to the expected future royalty payment.


51

Liquids

The following table summarizes the operating results of our Liquids segment for the periods indicated:
 
 
Three Months Ended September 30,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per gallon amounts)
Propane sales:
 
 
 
 
 
 
Revenues (1)
 
$
193,588

 
$
101,613

 
$
91,975

Cost of sales
 
176,363

 
96,663

 
79,700

Product margin
 
17,225

 
4,950

 
12,275

 
 
 
 
 
 
 
Butane sales:
 
 
 
 
 
 
Revenues (1)
 
111,545

 
66,680

 
44,865

Cost of sales
 
124,985

 
58,898

 
66,087

Product (loss) margin
 
(13,440
)
 
7,782

 
(21,222
)
 
 
 
 
 
 
 
Other product sales:
 
 
 
 
 
 
Revenues (1)
 
102,409

 
69,020

 
33,389

Cost of sales
 
93,884

 
61,214

 
32,670

Product margin
 
8,525

 
7,806

 
719

 
 
 
 
 
 
 
Other revenues:
 
 
 
 
 
 
Revenues (1)
 
3,928

 
8,075

 
(4,147
)
Cost of sales
 
684

 
3,636

 
(2,952
)
Product margin
 
3,244

 
4,439

 
(1,195
)
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
8,510

 
11,608

 
(3,098
)
General and administrative expenses
 
1,281

 
543

 
738

Depreciation and amortization expense
 
6,141

 
4,425

 
1,716

Loss on disposal or impairment of assets, net
 
117,729

 
17

 
117,712

Total expenses
 
133,661

 
16,593

 
117,068

Segment operating (loss) income
 
$
(118,107
)
 
$
8,384

 
$
(126,491
)
 
 
 
 
 
 
 
Liquids storage capacity - leased and owned (gallons) (2)
 
453,971

 
358,537

 
95,434

 
 
 
 
 
 
 
Propane sold (gallons)
 
257,775

 
222,352

 
35,423

Propane sold ($/gallon)
 
$
0.751

 
$
0.457

 
$
0.294

Cost per propane sold ($/gallon)
 
$
0.684

 
$
0.435

 
$
0.249

Propane product margin ($/gallon)
 
$
0.067

 
$
0.022

 
$
0.045

Propane inventory (gallons) (2)
 
136,980

 
146,995

 
(10,015
)
Propane storage capacity sub-leased to third parties - leased and owned (gallons) (2)
 
33,495

 
33,264

 
231

 
 
 
 
 
 
 
Butane sold (gallons)
 
125,419

 
102,147

 
23,272

Butane sold ($/gallon)
 
$
0.889

 
$
0.653

 
$
0.236

Cost per butane sold ($/gallon)
 
$
0.997

 
$
0.577

 
$
0.420

Butane product margin ($/gallon)
 
$
(0.108
)
 
$
0.076

 
$
(0.184
)
Butane inventory (gallons) (2)
 
111,632

 
72,369

 
39,263

Butane storage capacity sub-leased to third parties - leased and owned (gallons) (2)
 
80,346

 
72,540

 
7,806

 
 
 
 
 
 
 
Other products sold (gallons)
 
102,009

 
86,817

 
15,192

Other products sold ($/gallon)
 
$
1.004

 
$
0.795

 
$
0.209

Cost per other products sold ($/gallon)
 
$
0.920

 
$
0.705

 
$
0.215

Other products product margin ($/gallon)
 
$
0.084

 
$
0.090

 
$
(0.006
)
Other products inventory (gallons) (2)
 
8,810

 
9,014

 
(204
)
 
(1)
Revenues include $18.3 million and $11.1 million of intersegment sales during the three months ended September 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.
(2)
Information is presented as of September 30, 2017 and September 30, 2016, respectively.

52


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

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

Propane margins are higher due primarily to the increase in market prices outpacing the rise in inventory values.

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

Our cost of butane sales during the three months ended September 30, 2017 was increased by $18.2 million of net unrealized losses on derivatives, compared to an increase of $3.3 million of net unrealized losses on derivatives during the three months ended September 30, 2016. Additionally, our cost of butane sales was reduced by $0.6 million of net realized gains on derivatives and $0.6 million of net realized gains on derivatives during the three months ended September 30, 2017 and 2016, respectively.

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

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

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

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

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

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

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

Loss on Disposal or Impairment of Assets, Net. During the three months ended September 30, 2017, we recorded a goodwill impairment charge of $116.9 million due to the decreased demand for natural gas liquid storage and resulting decline in revenues and earnings as compared to actual and projected results of prior and future periods (see Note 6 to our unaudited condensed consolidated financial statements included in this Quarterly Report). During the three months ended September 30, 2017, we recorded a net loss of $0.9 million related to the retirement of assets. During the three months ended September 30, 2016, we recorded a net loss of less than $0.1 million related to the retirement of assets.


53

Retail Propane

The following table summarizes the operating results of our Retail Propane segment for the periods indicated:
 
 
Three Months Ended September 30,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per gallon amounts)
Propane sales:
 
 
 
 
 
 
Revenues (1)
 
$
48,004

 
$
36,170

 
$
11,834

Cost of sales
 
22,158

 
13,272

 
8,886

Product margin
 
25,846

 
22,898

 
2,948

 
 
 
 
 
 
 
Distillate sales:
 
 
 
 
 
 
Revenues (1)
 
6,676

 
5,589

 
1,087

Cost of sales
 
5,390

 
4,406

 
984

Product margin
 
1,286

 
1,183

 
103

 
 
 
 
 
 
 
Other revenues:
 
 
 
 
 
 
Revenues (1)
 
10,043

 
9,331

 
712

Cost of sales
 
3,772

 
3,013

 
759

Product margin
 
6,271

 
6,318

 
(47
)
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
28,201

 
27,132

 
1,069

General and administrative expenses
 
2,322

 
1,344

 
978

Depreciation and amortization expense
 
11,613

 
10,705

 
908

Loss (gain) on disposal or impairment of assets, net
 
493

 
(65
)
 
558

Total expenses
 
42,629

 
39,116

 
3,513

Segment operating loss
 
$
(9,226
)
 
$
(8,717
)
 
$
(509
)
 
 
 
 
 
 
 
Propane sold (gallons)
 
28,182

 
23,745

 
4,437

Propane sold ($/gallon)
 
$
1.703

 
$
1.523

 
$
0.180

Cost per propane sold ($/gallon)
 
$
0.786

 
$
0.559

 
$
0.227

Propane product margin ($/gallon)
 
$
0.917

 
$
0.964

 
$
(0.047
)
Propane inventory (gallons) (2)
 
11,183

 
10,625

 
558

 
 
 
 
 
 
 
Distillates sold (gallons)
 
3,203

 
2,949

 
254

Distillates sold ($/gallon)
 
$
2.084

 
$
1.895

 
$
0.189

Cost per distillates sold ($/gallon)
 
$
1.683

 
$
1.494

 
$
0.189

Distillates product margin ($/gallon)
 
$
0.401

 
$
0.401

 
$
—

Distillates inventory (gallons) (2)
 
2,793

 
3,083

 
(290
)
 
(1)
Revenues include less than $0.1 million of intersegment sales during the three months ended September 30, 2017 that are eliminated in our unaudited condensed consolidated statements of operations.
(2)
Information is presented as of September 30, 2017 and September 30, 2016, respectively.

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

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

54


Operating and General and Administrative Expenses. The increase was due primarily to increased operating expenses and integration costs from acquisitions of four retail propane businesses during the previous fiscal year and four retail propane businesses in the current year.

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

Loss (Gain) on Disposal or Impairment of Assets, Net. Amounts represent gains and losses on the sales of surplus assets.


55

Refined Products and Renewables

The following table summarizes the operating results of our Refined Products and Renewables segment for the periods indicated:
 
 
Three Months Ended September 30,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per barrel amounts)
Refined products sales:
 
 
 
 
 
 
Revenues (1)
 
$
2,874,268

 
$
2,274,715

 
$
599,553

Cost of sales
 
2,854,907

 
2,265,182

 
589,725

Product margin
 
19,361

 
9,533

 
9,828

 
 
 
 
 
 
 
Renewables sales:
 
 
 
 
 
 
Revenues
 
102,964

 
95,830

 
7,134

Cost of sales
 
103,036

 
94,852

 
8,184

Product (loss) margin
 
(72
)
 
978

 
(1,050
)
 
 
 
 
 
 
 
Service fee revenues
 
50

 
(121
)
 
171

 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
3,338

 
4,341

 
(1,003
)
General and administrative expenses
 
2,163

 
1,809

 
354

Depreciation and amortization expense
 
324

 
416

 
(92
)
Gain on disposal or impairment of assets, net
 
(7,528
)
 
(7,563
)
 
35

Total income
 
(1,703
)
 
(997
)
 
(706
)
Segment operating income
 
$
21,042

 
$
11,387

 
$
9,655

 
 
 
 
 
 
 
Gasoline sold (barrels)
 
26,459

 
23,107

 
3,352

Diesel sold (barrels)
 
14,990

 
14,341

 
649

Ethanol sold (barrels)
 
978

 
1,035

 
(57
)
Biodiesel sold (barrels)
 
568

 
464

 
104

Refined products and renewables storage capacity - leased (barrels) (2)
 
9,070

 
7,645

 
1,425

Refined products and renewables storage capacity sub-leased to third parties (barrels) (2)
 
1,043

 
1,063

 
(20
)
Gasoline inventory (barrels) (2)
 
1,862

 
1,995

 
(133
)
Diesel inventory (barrels) (2)
 
1,148

 
2,339

 
(1,191
)
Ethanol inventory (barrels) (2)
 
513

 
372

 
141

Biodiesel inventory (barrels) (2)
 
375

 
260

 
115

Refined products sold ($/barrel)
 
$
69.345

 
$
60.743

 
$
8.602

Cost per refined products sold ($/barrel)
 
$
68.878

 
$
60.489

 
$
8.389

Refined products product margin ($/barrel)
 
$
0.467

 
$
0.254

 
$
0.213

Renewable products sold ($/barrel)
 
$
66.600

 
$
63.929

 
$
2.671

Cost per renewable products sold ($/barrel)
 
$
66.647

 
$
63.277

 
$
3.370

Renewable products product margin ($/barrel)
 
$
(0.047
)
 
$
0.652

 
$
(0.699
)
 
(1)
Revenues include $0.1 million and $0.1 million of intersegment sales during the three months ended September 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.
(2)
Information is presented as of September 30, 2017 and September 30, 2016, respectively.

Refined Products Revenues and Cost of Sales. The increases in revenues and cost of sales were due to an increase in refined products prices and increased volumes. The increased volumes were due primarily to an expansion of our refined

56

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

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

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

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

Gain on Disposal or Impairment of Assets, Net. During the three months ended September 30, 2017, we recorded $7.5 million of the deferred gain from the sale of the general partner in interest in TLP in February 2016 (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion).

During the three months ended September 30, 2016, we recorded:

•
$7.5 million of the deferred gain from the sale of the general partner in interest in TLP in February 2016 (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion); and
•
a gain of less than $0.1 million on the sales of certain assets.

Corporate and Other

The operating loss within “Corporate and Other” includes the following components for the periods indicated:
 
 
Three Months Ended September 30,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands)
Other revenues
 
$
246

 
$
248

 
$
(2
)
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Cost of sales
 
121

 
113

 
8

Operating expenses
 
258

 
239

 
19

General and administrative expenses
 
15,407

 
22,409

 
(7,002
)
Depreciation and amortization expense
 
919

 
903

 
16

Gain on disposal or impairment of assets, net
 
—

 
(3
)
 
3

Total expenses
 
16,705

 
23,661

 
(6,956
)
Operating loss
 
$
(16,459
)
 
$
(23,413
)
 
$
6,954


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

The decrease in incentive compensation was primarily related to our service awards units. During the three months ended September 30, 2017, expense related to the service award units was $3.3 million, compared to $6.9 million during the three months ended September 30, 2016. During the three months ended September 30, 2017, the expense for the service award units was lower due to the cancellation of certain service awards in the prior year quarter for which the expense had to be accelerated, as well as in the current year the number of units granted was significantly less than the number of units that have vested, thus, expense related to new grants has not fully replaced the expense from units that have fully vested during the period. In addition, compensation expense of $2.8 million was shifted from our Liquids segment during the three months ended September 30, 2017 due to our expectation of paying these amounts in common units.

 

57

Equity in Earnings of Unconsolidated Entities

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

Interest Expense

Interest expense includes interest expense on our Revolving Credit Facility and senior notes, amortization of debt issuance costs, letter of credit fees, interest on equipment financing notes, and accretion of interest on non-interest bearing debt obligations. The increase of $16.8 million during the three months ended September 30, 2017 was due primarily to the issuance of $700.0 million of fixed-rate notes during October 2016 and the issuance of $500.0 million of fixed-rate notes during February 2017.

Gain on Early Extinguishment of Liabilities, Net

The following table summarizes the components of gain on early extinguishment of liabilities, net for the periods indicated:
 
Three Months Ended September 30,
 
2017
 
2016
 
(in thousands)
Early extinguishment of long-term debt (1)
$
1,943

 
$
—

Release of contingent consideration liabilities (2)
—

 
938

Gain on early extinguishment of liabilities, net
$
1,943

 
$
938

 
(1)
During the three months ended September 30, 2017, this relates to gains on the early extinguishment of a portion of the 2019 Notes, the 2023 Notes and the 2025 Notes. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.
(2)
During the three months ended September 30, 2016, we acquired certain parcels of land on which one of our water solutions facilities is located and recorded a gain on the release of certain contingent consideration liabilities as the royalty agreement was terminated.

Other Income, Net

The following table summarizes the components of other income, net for the periods indicated:
 
Three Months Ended September 30,
 
2017
 
2016
 
(in thousands)
Interest income (1)
$
1,880

 
$
1,997

Crude oil marketing arrangement (2)
(1
)
 
(30
)
Other
17

 
114

Other income, net
$
1,896

 
$
2,081

 
(1)
Relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party and to a loan receivable from an equity method investee (see Note 2 and Note 13, respectively, to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion).
(2)
Represents another party’s share of the profits and losses generated from a joint crude oil marketing arrangement.

Income Tax Expense

Income tax expense was $0.1 million during the three months ended September 30, 2017, compared to income tax expense of $0.5 million during the three months ended September 30, 2016. The decrease in income tax expense was due primarily to a lower state franchise tax liability in Texas from a lower tax rate and lower Texas revenues as well as a lower Canadian tax liability from lower income in our taxable corporate subsidiaries in Canada. See Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.



58

Segment Operating Results for the Six Months Ended September 30, 2017 and 2016

Crude Oil Logistics

The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated:
 
 
Six Months Ended September 30,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per barrel amounts)
Revenues:
 
 
 
 
 
 
Crude oil sales
 
$
890,559

 
$
756,600

 
$
133,959

Crude oil transportation and other
 
56,301

 
22,106

 
34,195

Total revenues (1)
 
946,860

 
778,706

 
168,154

Expenses:
 
 

 
 

 
 

Cost of sales
 
875,563

 
748,618

 
126,945

Operating expenses
 
24,367

 
18,822

 
5,545

General and administrative expenses
 
3,300

 
2,975

 
325

Depreciation and amortization expense
 
41,793

 
17,993

 
23,800

(Gain) loss on disposal or impairment of assets, net
 
(3,716
)
 
9,962

 
(13,678
)
Total expenses
 
941,307

 
798,370

 
142,937

Segment operating income (loss)
 
$
5,553

 
$
(19,664
)
 
$
25,217

 
 
 
 
 
 
 
Crude oil sold (barrels)
 
18,582

 
17,311

 
1,271

Crude oil transported on owned pipelines (barrels)
 
14,948

 
—

 
14,948

Crude oil storage capacity - owned and leased (barrels) (2)
 
6,159

 
6,355

 
(196
)
Crude oil storage capacity sub-leased to third parties (barrels) (2)
 
700

 
2,000

 
(1,300
)
Crude oil inventory (barrels) (2)
 
1,682

 
1,982

 
(300
)
Crude oil sold ($/barrel)
 
$
47.926

 
$
43.706

 
$
4.220

Cost per crude oil sold ($/barrel)
 
$
47.119

 
$
43.245

 
$
3.874

Crude oil product margin ($/barrel)
 
$
0.807

 
$
0.461

 
$
0.346

 
(1)
Revenues include $4.9 million and $2.9 million of intersegment sales during the six months ended September 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.
(2)
Information is presented as of September 30, 2017 and September 30, 2016, respectively.

Crude Oil Sales. The increase was due primarily to an increase in crude oil prices and barrels sold during the six months ended September 30, 2017, compared to the six months ended September 30, 2016. This segment continued to be impacted by competition and low margins in the majority of the basins across the United States and we continue to market crude volumes in this lower price environment to support our various pipeline, terminal and transportation assets.

Crude Oil Transportation and Other Revenues. The increase was due primarily to our Grand Mesa Pipeline becoming operational on November 1, 2016 with revenues of $38.4 million and higher revenues in our trucking operations during the six months ended September 30, 2017, due to an increase in demand for transportation services, compared to the six months ended September 30, 2016, partially offset by the flattening of the contango curve for crude oil (a condition in which forward crude oil prices are greater than spot prices) during the six months ended September 30, 2017, compared to the six months ended September 30, 2016.

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


59

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

Depreciation and Amortization Expense. The increase was due primarily to our Grand Mesa Pipeline project becoming operational on November 1, 2016. During the six months ended September 30, 2017, we incurred depreciation and amortization expense of $21.1 million related to Grand Mesa. Also contributing to the increase was higher depreciation expense related to other capital projects being placed into service.

(Gain) Loss on Disposal or Impairment of Assets, Net. During the six months ended September 30, 2017, we recorded a net gain of $3.7 million on the sales of excess pipe and certain other assets. During the six months ended September 30, 2016, we recorded a net loss of $6.3 million on the sales of certain assets and a loss of $3.7 million due to the write-down of certain other assets.

Water Solutions

The following table summarizes the operating results of our Water Solutions segment for the periods indicated:
 
 
Six Months Ended September 30,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per barrel and per day amounts)
Revenues:
 
 
 
 
 
 
Service fees
 
$
68,603

 
$
54,225

 
$
14,378

Recovered hydrocarbons
 
20,406

 
12,877

 
7,529

Other revenues
 
8,990

 
8,384

 
606

Total revenues
 
97,999

 
75,486

 
22,513

Expenses:
 
 
 
 
 
 
Cost of sales-derivative loss
 
2,048

 
2,687

 
(639
)
Cost of sales-other
 
779

 
707

 
72

Operating expenses
 
47,529

 
40,505

 
7,024

General and administrative expenses
 
1,299

 
1,271

 
28

Depreciation and amortization expense
 
49,261

 
49,563

 
(302
)
Loss (gain) on disposal or impairment of assets, net
 
185

 
(94,281
)
 
94,466

Revaluation of liabilities
 
5,600

 
—

 
5,600

Total expenses
 
106,701

 
452

 
106,249

Segment operating (loss) income
 
$
(8,702
)
 
$
75,034

 
$
(83,736
)
 
 
 
 
 
 
 
Wastewater processed (barrels per day)
 
 
 
 
 
 
Eagle Ford Basin
 
215,156

 
209,936

 
5,220

Permian Basin
 
252,810

 
168,927

 
83,883

DJ Basin
 
110,685

 
59,950

 
50,735

Other Basins
 
61,223

 
38,913

 
22,310

Total
 
639,874

 
477,726

 
162,148

Solids processed (barrels per day)
 
4,986

 
2,652

 
2,334

Skim oil sold (barrels per day)
 
2,572

 
1,773

 
799

Service fees for wastewater processed ($/barrel)
 
$
0.59

 
$
0.62

 
$
(0.03
)
Recovered hydrocarbons for wastewater processed ($/barrel)
 
$
0.17

 
$
0.15

 
$
0.02

Operating expenses for wastewater processed ($/barrel)
 
$
0.41

 
$
0.46

 
$
(0.05
)

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

60


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

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

Cost of Sales-Derivatives. We enter into derivatives in our Water Solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expect to recover when processing the wastewater and selling the skim oil. Our cost of sales during the six months ended September 30, 2017 included $1.0 million of net realized gains on derivatives and $3.0 million of net unrealized losses on derivatives. Our cost of sales during the six months ended September 30, 2016 included $3.5 million of net realized losses on derivatives and $0.8 million of net unrealized gains on derivatives.

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

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

Depreciation and Amortization Expense. The decrease was due primarily to lower amortization expense from the write-off of an intangible asset during the six months ended September 30, 2016 as well as certain intangible assets being fully amortized during the fiscal year ended March 31, 2017, partially offset by acquisitions and developed facilities.

Loss (Gain) on Disposal or Impairment of Assets, Net. During the six months ended September 30, 2017, we recorded a net loss of $1.5 million on the sales of certain assets, partially offset by a gain of $1.3 million for the termination of a non-compete agreement, which included the carrying value of the non-compete agreement intangible asset that was written off (see Note 7 to our unaudited condensed consolidated financial statements included in this Quarterly Report).

During the six months ended September 30, 2016, we recorded:

•
an adjustment of $124.7 million of the previously recorded $380.2 million estimated goodwill impairment charge recorded during the three months ended March 31, 2016;
•
a write-off of $5.2 million related to the value of an indefinite-lived trade name intangible asset in conjunction with finalizing our goodwill impairment analysis in June 2016;
•
a loss of $22.7 million related to the termination of a development agreement in June 2016, which included the carrying value of the development agreement asset that was written off;
•
an impairment charge of $1.7 million to write down a loan receivable in June 2016; and
•
a loss of $0.8 million on the sales of certain assets.

Revaluation of Liabilities. The revaluation of liabilities represents the change in the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations during the fiscal year ended March 31, 2017. The increase in the expense during the six months ended September 30, 2017 was due primarily to higher actual and expected production from new customers, resulting in an increase to the expected future royalty payment.


61

Liquids

The following table summarizes the operating results of our Liquids segment for the periods indicated:
 
 
Six Months Ended September 30,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per gallon amounts)
Propane sales:
 
 
 
 
 
 
Revenues (1)
 
$
330,448

 
$
198,084

 
$
132,364

Cost of sales
 
314,274

 
187,826

 
126,448

Product margin
 
16,174

 
10,258

 
5,916

 
 
 
 
 
 
 
Butane sales:
 
 
 
 
 
 
Revenues (1)
 
179,777

 
121,255

 
58,522

Cost of sales
 
191,247

 
112,836

 
78,411

Product (loss) margin
 
(11,470
)
 
8,419

 
(19,889
)
 
 
 
 
 
 
 
Other product sales:
 
 
 
 
 
 
Revenues (1)
 
186,712

 
128,180

 
58,532

Cost of sales
 
177,540

 
117,386

 
60,154

Product margin
 
9,172

 
10,794

 
(1,622
)
 
 
 
 
 
 
 
Other revenues:
 
 
 
 
 
 
Revenues (1)
 
9,940

 
15,222

 
(5,282
)
Cost of sales
 
1,522

 
5,659

 
(4,137
)
Product margin
 
8,418

 
9,563

 
(1,145
)
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
16,352

 
19,540

 
(3,188
)
General and administrative expenses
 
2,621

 
2,244

 
377

Depreciation and amortization expense
 
12,471

 
8,874

 
3,597

Loss on disposal or impairment of assets, net
 
117,729

 
49

 
117,680

Total expenses
 
149,173

 
30,707

 
118,466

Segment operating (loss) income
 
$
(126,879
)
 
$
8,327

 
$
(135,206
)
 
 
 
 
 
 
 
Liquids storage capacity - leased and owned (gallons) (2)
 
453,971

 
358,537

 
95,434

 
 
 
 
 
 
 
Propane sold (gallons)
 
482,508

 
426,636

 
55,872

Propane sold ($/gallon)
 
$
0.685

 
$
0.464

 
$
0.221

Cost per propane sold ($/gallon)
 
$
0.651

 
$
0.440

 
$
0.211

Propane product margin ($/gallon)
 
$
0.034

 
$
0.024

 
$
0.010

Propane inventory (gallons) (2)
 
136,980

 
146,995

 
(10,015
)
Propane storage capacity sub-leased to third parties - leased and owned (gallons) (2)
 
33,495

 
33,264

 
231

 
 
 
 
 
 
 
Butane sold (gallons)
 
216,936

 
198,455

 
18,481

Butane sold ($/gallon)
 
$
0.829

 
$
0.611

 
$
0.218

Cost per butane sold ($/gallon)
 
$
0.882

 
$
0.569

 
$
0.313

Butane product margin ($/gallon)
 
$
(0.053
)
 
$
0.042

 
$
(0.095
)
Butane inventory (gallons) (2)
 
111,632

 
72,369

 
39,263

Butane storage capacity sub-leased to third parties - leased and owned (gallons) (2)
 
80,346

 
72,540

 
7,806

 
 
 
 
 
 
 
Other products sold (gallons)
 
192,620

 
166,477

 
26,143

Other products sold ($/gallon)
 
$
0.969

 
$
0.770

 
$
0.199

Cost per other products sold ($/gallon)
 
$
0.922

 
$
0.705

 
$
0.217

Other products product margin ($/gallon)
 
$
0.047

 
$
0.065

 
$
(0.018
)
Other products inventory (gallons) (2)
 
8,810

 
9,014

 
(204
)
 
(1)
Revenues include $35.9 million and $23.4 million of intersegment sales during the six months ended September 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.
(2)
Information is presented as of September 30, 2017 and September 30, 2016, respectively.

62


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

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

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

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

Our cost of butane sales during the six months ended September 30, 2017 was increased by $16.5 million of net unrealized losses on derivatives, compared to an increase of $5.3 million of net unrealized losses on derivatives during the six months ended September 30, 2016. Additionally, our cost of butane sales was reduced by $0.8 million of net realized gains on derivatives and $1.0 million of net realized gains on derivatives during the six months ended September 30, 2017 and 2016, respectively, due to the steady increase in commodity prices beginning in July 2017.

Product margins per gallon of butane sold were lower during the six months ended September 30, 2017 than during the six months ended September 30, 2016 due primarily to the unrealized losses on derivatives noted above. The butane product margins, excluding the unrealized losses on derivatives, were $0.023 per gallon for the six months ended September 30, 2017.

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

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

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

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

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

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

Loss on Disposal or Impairment of Assets, Net. During the six months ended September 30, 2017, we recorded a goodwill impairment charge of $116.9 million due to the decreased demand for natural gas liquid storage and resulting decline in revenues and earnings as compared to actual and projected results of prior and future periods (see Note 6 to our unaudited condensed consolidated financial statements included in this Quarterly Report). During the six months ended September 30, 2017, we recorded a net loss of $0.9 million related to the retirement of assets. During the six months ended September 30, 2016, we recorded a net loss of less than $0.1 million related to the retirement of assets.


63

Retail Propane

The following table summarizes the operating results of our Retail Propane segment for the periods indicated:
 
 
Six Months Ended September 30,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per gallon amounts)
Propane sales:
 
 
 
 
 
 
Revenues (1)
 
$
96,636

 
$
77,811

 
$
18,825

Cost of sales
 
42,338

 
28,101

 
14,237

Product margin
 
54,298

 
49,710

 
4,588

 
 
 
 
 
 
 
Distillate sales:
 
 
 
 
 
 
Revenues (1)
 
16,231

 
16,044

 
187

Cost of sales
 
12,405

 
11,944

 
461

Product margin
 
3,826

 
4,100

 
(274
)
 
 
 
 
 
 
 
Other revenues:
 
 
 
 
 
 
Revenues (1)
 
18,936

 
17,638

 
1,298

Cost of sales
 
6,213

 
5,466

 
747

Product margin
 
12,723

 
12,172

 
551

 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
56,842

 
52,349

 
4,493

General and administrative expenses
 
4,928

 
4,494

 
434

Depreciation and amortization expense
 
23,075

 
20,392

 
2,683

Loss (gain) on disposal or impairment of assets, net
 
1,096

 
(34
)
 
1,130

Total expenses
 
85,941

 
77,201

 
8,740

Segment operating loss
 
$
(15,094
)
 
$
(11,219
)
 
$
(3,875
)
 
 
 
 
 
 
 
Propane sold (gallons)
 
55,430

 
49,361

 
6,069

Propane sold ($/gallon)
 
$
1.743

 
$
1.576

 
$
0.167

Cost per propane sold ($/gallon)
 
$
0.764

 
$
0.569

 
$
0.195

Propane product margin ($/gallon)
 
$
0.979

 
$
1.007

 
$
(0.028
)
Propane inventory (gallons) (2)
 
11,183

 
10,625

 
558

 
 
 
 
 
 
 
Distillates sold (gallons)
 
7,707

 
8,366

 
(659
)
Distillates sold ($/gallon)
 
$
2.106

 
$
1.918

 
$
0.188

Cost per distillates sold ($/gallon)
 
$
1.610

 
$
1.428

 
$
0.182

Distillates product margin ($/gallon)
 
$
0.496

 
$
0.490

 
$
0.006

Distillates inventory (gallons) (2)
 
2,793

 
3,083

 
(290
)
 
(1)
Revenues include less than $0.1 million and less than $0.1 million of intersegment sales during the six months ended September 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statement of operations.
(2)
Information is presented as of September 30, 2017 and September 30, 2016, respectively.

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

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


64

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

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

Loss (Gain) on Disposal or Impairment of Assets, Net. Amounts represent gains and losses on the sales of surplus assets.


65

Refined Products and Renewables

The following table summarizes the operating results of our Refined Products and Renewables segment for the periods indicated:
 
 
Six Months Ended September 30,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands, except per barrel amounts)
Refined products sales:
 
 
 
 
 
 
Revenues (1)
 
$
5,647,875

 
$
4,151,572

 
$
1,496,303

Cost of sales
 
5,615,979

 
4,099,509

 
1,516,470

Product margin
 
31,896

 
52,063

 
(20,167
)
 
 
 
 
 
 
 
Renewables sales:
 
 
 
 
 
 
Revenues
 
213,930

 
202,312

 
11,618

Cost of sales
 
213,720

 
200,654

 
13,066

Product margin
 
210

 
1,658

 
(1,448
)
 
 
 
 
 
 
 
Service fee revenues
 
168

 
11,145

 
(10,977
)
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
6,889

 
16,663

 
(9,774
)
General and administrative expenses
 
4,255

 
5,374

 
(1,119
)
Depreciation and amortization expense
 
648

 
833

 
(185
)
Gain on disposal or impairment of assets, net
 
(15,056
)
 
(119,160
)
 
104,104

Total income
 
(3,264
)
 
(96,290
)
 
93,026

Segment operating income
 
$
35,538

 
$
161,156

 
$
(125,618
)
 
 
 
 
 
 
 
Gasoline sold (barrels)
 
54,975

 
43,051

 
11,924

Diesel sold (barrels)
 
28,788

 
25,200

 
3,588

Ethanol sold (barrels)
 
1,992

 
2,065

 
(73
)
Biodiesel sold (barrels)
 
1,195

 
1,215

 
(20
)
Refined products and renewables storage capacity - leased (barrels) (2)
 
9,070

 
7,645

 
1,425

Refined products and renewables storage capacity sub-leased to third parties (barrels) (2)
 
1,043

 
1,063

 
(20
)
Gasoline inventory (barrels) (2)
 
1,862

 
1,995

 
(133
)
Diesel inventory (barrels) (2)
 
1,148

 
2,339

 
(1,191
)
Ethanol inventory (barrels) (2)
 
513

 
372

 
141

Biodiesel inventory (barrels) (2)
 
375

 
260

 
115

Refined products sold ($/barrel)
 
$
67.427

 
$
60.828

 
$
6.599

Cost per refined products sold ($/barrel)
 
$
67.046

 
$
60.065

 
$
6.981

Refined products product margin ($/barrel)
 
$
0.381

 
$
0.763

 
$
(0.382
)
Renewable products sold ($/barrel)
 
$
67.126

 
$
61.680

 
$
5.446

Cost per renewable products sold ($/barrel)
 
$
67.060

 
$
61.175

 
$
5.885

Renewable products product margin ($/barrel)
 
$
0.066

 
$
0.505

 
$
(0.439
)
 
(1)
Revenues include $0.1 million and $0.1 million of intersegment sales during the six months ended September 30, 2017 and 2016, respectively, that are eliminated in our unaudited condensed consolidated statements of operations.
(2)
Information is presented as of September 30, 2017 and September 30, 2016, respectively.

Refined Products Revenues and Cost of Sales. The increases in revenues and cost of sales were due to an increase in refined products prices and increased volumes. The increased volumes were due primarily to additional pipeline capacity rights

66

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

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

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

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

Gain on Disposal or Impairment of Assets, Net. During the six months ended September 30, 2017, we recorded $15.1 million of the deferred gain from the sale of the general partner in interest in TLP in February 2016 (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion).

During the six months ended September 30, 2016, we recorded:

•
a $104.1 million gain from the sale of all of the TLP units we owned;
•
$15.1 million of the deferred gain from the sale of the general partner in interest in TLP in February 2016 (see Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion); and
•
a gain of less than $0.1 million on the sales of certain assets.

Corporate and Other

The operating loss within “Corporate and Other” includes the following components for the periods indicated:
 
 
Six Months Ended September 30,
 
 
 
 
2017
 
2016
 
Change
 
 
(in thousands)
Other revenues
 
$
407

 
$
515

 
$
(108
)
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Cost of sales
 
194

 
223

 
(29
)
Operating expenses
 
491

 
564

 
(73
)
General and administrative expenses
 
32,068

 
53,439

 
(21,371
)
Depreciation and amortization expense
 
1,839

 
1,854

 
(15
)
Gain on disposal or impairment of assets, net
 
—

 
(3
)
 
3

Total expenses
 
34,592

 
56,077

 
(21,485
)
Operating loss
 
$
(34,185
)
 
$
(55,562
)
 
$
21,377


General and Administrative Expenses. The expense associated with the service award units was $8.6 million during the six months ended September 30, 2017, compared to $27.7 million during the six months ended September 30, 2016. During the six months ended September 30, 2017, due to the cancellation of awards in the prior year which caused an acceleration of expense as well as vested units in July were not offset by grants as in the prior year. In addition, during the first quarter of our prior fiscal year the expense for the service awards being accounted for under the liability method and due to an increase in our unit price during that period we recorded an increase in equity-based compensation expense. See Note 10 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion of our equity-based compensation awards. The decrease from the prior year was partially offset by $2.8 million of compensation expense that was shifted from our Liquids segment during the three months ended September 30, 2017 due to our expectation of paying these amounts in common units.

67


 
Equity in Earnings of Unconsolidated Entities

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

Revaluation of Investments

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

Interest Expense

The increase of $35.6 million during the six months ended September 30, 2017 was due primarily to the issuance of $700.0 million of fixed-rate notes during October 2016 and the issuance of $500.0 million of fixed-rate notes during February 2017. The increase was partially offset by lower interest expense related to our credit facility. The average daily balance of our credit facility was $0.9 billion during the six months ended September 30, 2017, compared to $1.9 billion during the six months ended September 30, 2016.

(Loss) Gain on Early Extinguishment of Liabilities, Net

The following table summarizes the components of (loss) gain on early extinguishment of liabilities, net for the periods indicated:
 
Six Months Ended September 30,
 
2017
 
2016
 
(in thousands)
Early extinguishment of long-term debt (1)
$
(1,338
)
 
$
8,614

Release of contingent consideration liabilities (2)
—

 
22,276

(Loss) gain on early extinguishment of liabilities, net
$
(1,338
)
 
$
30,890

 
(1)
During the six months ended September 30, 2017, this relates to net losses on the early extinguishment of a portion of the senior secured notes, the 2019 Notes, the 2023 Notes and the 2025 Notes. During the six months ended September 30, 2016, this relates to gains on the early extinguishment of a portion of the 2019 Notes and the 6.875% senior notes due 2021 (“2021 Notes”). See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.
(2)
Relates to the release of certain contingent consideration liabilities in conjunction with the termination of a development agreement in June 2016. Also, during the three months ended September 30, 2016, we acquired certain parcels of land on which one of our water solutions facilities is located and recorded a gain on the release of certain contingent consideration liabilities as the royalty agreement was terminated.


68

Other Income, Net

The following table summarizes the components of other income, net for the periods indicated:
 
Six Months Ended September 30,
 
2017
 
2016
 
(in thousands)
Interest income (1)
$
3,958

 
$
4,420

Crude oil marketing arrangement (2)
(10
)
 
(1,551
)
Other (3)
58

 
2,984

Other income, net
$
4,006

 
$
5,853

 
(1)
Relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party and to a loan receivable from an equity method investee (see Note 2 and Note 13, respectively, to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion). As previously reported, on June 3, 2016, we acquired the remaining 65% ownership interest in Grassland and all interest income on that receivable has been eliminated in consolidation subsequent to that date.
(2)
Represents another party’s share of the profits and losses generated from a joint crude oil marketing arrangement.
(3)
During the six months ended September 30, 2016, this relates primarily to a distribution from TLP pursuant to the agreement to sell all of the TLP common units we owned in April 2016.

Income Tax Expense

Income tax expense was $0.6 million during the six months ended September 30, 2017, compared to income tax expense of $0.9 million during the six months ended September 30, 2016. The decrease in income tax expense was due primarily to a lower state franchise tax liability in Texas from a lower tax rate and lower Texas revenues as well as a lower Canadian tax liability from lower income in our taxable corporate subsidiaries in Canada. See Note 2 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion.

Noncontrolling Interests - Redeemable and Non-redeemable

Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. The decrease of $6.3 million during the six months ended September 30, 2017 was due primarily to adjustments related to noncontrolling interests during the six months ended September 30, 2016.

Non-GAAP Financial Measures

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

We define EBITDA as net income (loss) attributable to NGL Energy Partners LP, plus interest expense, income tax expense (benefit), and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding net unrealized gains and losses on derivatives, lower of cost or market adjustments, gains and losses on disposal or impairment of assets, gains and losses on early extinguishment of liabilities, revaluation of investments, equity-based compensation expense, acquisition expense, revaluation of liabilities and other. We also include in Adjusted EBITDA certain inventory valuation adjustments related to our Refined Products and Renewables segment, as discussed below. EBITDA and Adjusted EBITDA should not be considered alternatives to net (loss) income, (loss) income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information to investors for evaluating our ability to make quarterly distributions to our unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information to investors for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA, Adjusted EBITDA, or similarly titled measures used by other entities.

69


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

The following table reconciles net (loss) income to EBITDA and Adjusted EBITDA:
 
Three Months Ended September 30,
 
Six Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Net (loss) income
$
(173,579
)
 
$
(66,658
)
 
$
(237,286
)
 
$
116,095

Less: Net (income) loss attributable to noncontrolling interests
(80
)
 
59

 
(132
)
 
(5,774
)
Less: Net loss attributable to redeemable noncontrolling interests
288

 
—

 
685

 
—

Net (loss) income attributable to NGL Energy Partners LP
(173,371
)
 
(66,599
)
 
(236,733
)
 
110,321

Interest expense
50,288

 
33,489

 
99,566

 
63,797

Income tax expense
111

 
460

 
570

 
922

Depreciation and amortization
69,426

 
54,522

 
137,489

 
107,102

EBITDA
(53,546
)
 
21,872

 
892

 
282,142

Net unrealized losses on derivatives
18,077

 
2,293

 
16,076

 
3,220

Inventory valuation adjustment (1)
(2,165
)
 
39,530

 
(21,347
)
 
32,693

Lower of cost or market adjustments
5,333

 
(393
)
 
9,411

 
108

Loss (gain) on disposal or impairment of assets, net
111,451

 
851

 
100,238

 
(203,504
)
(Gain) loss on early extinguishment of liabilities, net
(1,943
)
 
(938
)
 
1,338

 
(30,890
)
Revaluation of investments
—

 
—

 
—

 
14,365

Equity-based compensation expense (2)
6,065

 
10,660

 
14,886

 
32,994

Acquisition expense (3)
264

 
724

 
(54
)
 
1,161

Revaluation of liabilities
5,600

 
—

 
5,600

 
—

Other (4)
1,616

 
889

 
2,641

 
7,117

Adjusted EBITDA
$
90,752

 
$
75,488

 
$
129,681

 
$
139,406

 
(1)
Amount reflects the difference between the market value of the inventory of our Refined Products and Renewables segment at the balance sheet date and its cost. See “Non-GAAP Financial Measures” section above for a further discussion.
(2)
Equity-based compensation expense in the table above may differ from equity-based compensation expense reported in Note 10 to our unaudited condensed consolidated financial statements included in this Quarterly Report. Amounts reported in the table above include expense accruals for bonuses expected to be paid in common units, whereas the amounts reported in Note 10 to our unaudited condensed consolidated financial statements only include expenses associated with equity-based awards that have been formally granted.
(3)
Amounts for the three months ended September 30, 2017 and 2016 and the six months ended September 30, 2016 represent expenses we incurred related to legal and advisory costs associated with acquisitions. The amount for the six months ended September 30, 2017 represents reimbursement for certain legal costs incurred in prior periods, partially offset by expenses we incurred related to legal and advisory costs associated with acquisitions.
(4)
Amounts for the three months ended September 30, 2017 and 2016 and the six months ended September 30, 2017 represent non-cash operating expenses related to our Grand Mesa Pipeline and accretion expense for asset retirement obligations. The amount for the six months ended September 30, 2016 represents non-cash operating expenses related to our Grand Mesa Pipeline, adjustments related to noncontrolling interests and accretion expense for asset retirement obligations.

70

The following tables reconcile depreciation and amortization amounts per the EBITDA table above to depreciation and amortization amounts reported in our unaudited condensed consolidated statements of operations and unaudited condensed consolidated statements of cash flows for the periods indicated:
 
 
Three Months Ended September 30,
 
Six Months Ended September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(in thousands)
Reconciliation to unaudited condensed consolidated statements of operations:
 
 
 
 
 
 
 
 
Depreciation and amortization per EBITDA table
 
$
69,426

 
$
54,522

 
$
137,489

 
$
107,102

Intangible asset amortization recorded to cost of sales
 
(1,506
)
 
(1,749
)
 
(3,091
)
 
(3,345
)
Depreciation and amortization of unconsolidated entities
 
(3,029
)
 
(2,999
)
 
(6,028
)
 
(6,068
)
Depreciation and amortization attributable to noncontrolling interests
 
317

 
829

 
717

 
1,820

Depreciation and amortization per unaudited condensed consolidated statements of operations
 
$
65,208

 
$
50,603

 
$
129,087

 
$
99,509


 
 
Six Months Ended September 30,
 
 
2017
 
2016
 
 
(in thousands)
Reconciliation to unaudited condensed consolidated statements of cash flows:
 
 
 
 
Depreciation and amortization per EBITDA table
 
$
137,489

 
$
107,102

Amortization of debt issuance costs recorded to interest expense
 
5,509

 
5,279

Depreciation and amortization of unconsolidated entities
 
(6,028
)
 
(6,068
)
Depreciation and amortization attributable to noncontrolling interests
 
717

 
1,820

Depreciation and amortization per unaudited condensed consolidated statements of cash flows
 
$
137,687

 
$
108,133


The following table reconciles interest expense per the EBITDA table above to interest expense reported in our unaudited condensed consolidated statements of operations for the periods indicated:
 
 
Three Months Ended September 30,
 
Six Months Ended September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(in thousands)
Interest expense per EBITDA table
 
$
50,288

 
$
33,489

 
$
99,566

 
$
63,797

Interest expense attributable to noncontrolling interests
 
9

 
4

 
18

 
8

Interest expense attributable to unconsolidated entities
 
(64
)
 
(51
)
 
(125
)
 
75

Interest expense per unaudited condensed consolidated statements of operations
 
$
50,233

 
$
33,442

 
$
99,459

 
$
63,880



71

The following tables reconcile operating income (loss) to Adjusted EBITDA by segment for the periods indicated. We have reclassified certain prior period information to be consistent with the classification methods used in the current fiscal year.
 
 
Three Months Ended September 30, 2017
 
 
Crude Oil
Logistics
 
Water
Solutions
 
Liquids
 
Retail
Propane
 
Refined
Products
and
Renewables
 
Corporate
and
Other
 
Consolidated
 
 
(in thousands)
Operating income (loss)
 
$
1,196

 
$
(7,548
)
 
$
(118,107
)
 
$
(9,226
)
 
$
21,042

 
$
(16,459
)
 
$
(129,102
)
Depreciation and amortization
 
20,958

 
25,253

 
6,141

 
11,613

 
324

 
919

 
65,208

Amortization recorded to cost of sales
 
84

 
—

 
71

 
—

 
1,351

 
—

 
1,506

Net unrealized losses on derivatives
 
2,170

 
3,022

 
12,682

 
203

 
—

 
—

 
18,077

Inventory valuation adjustment
 
—

 
—

 
—

 
—

 
(2,165
)
 
—

 
(2,165
)
Lower of cost or market adjustments
 
—

 
—

 
(2,476
)
 
—

 
7,809

 
—

 
5,333

(Gain) loss on disposal or impairment of assets, net
 
(157
)
 
915

 
117,729

 
493

 
(7,528
)
 
—

 
111,452

Equity-based compensation expense
 
—

 
—

 
—

 
—

 
—

 
6,065

 
6,065

Acquisition expense
 
—

 
—

 
—

 
—

 
—

 
264

 
264

Other income, net
 
50

 
2

 
3

 
69

 
167

 
1,605

 
1,896

Adjusted EBITDA attributable to unconsolidated entities
 
3,798

 
127

 
—

 
(19
)
 
1,216

 
—

 
5,122

Adjusted EBITDA attributable to noncontrolling interest
 
—

 
(190
)
 
—

 
70

 
—

 
—

 
(120
)
Revaluation of liabilities
 
—

 
5,600

 
—

 
—

 
—

 
—

 
5,600

Other
 
1,502

 
92

 
22

 
—

 
—

 
—

 
1,616

Adjusted EBITDA
 
$
29,601

 
$
27,273

 
$
16,065

 
$
3,203

 
$
22,216

 
$
(7,606
)
 
$
90,752

 
 
Three Months Ended September 30, 2016
 
 
Crude Oil
Logistics
 
Water
Solutions
 
Liquids
 
Retail
Propane
 
Refined
Products
and
Renewables
 
Corporate
and
Other
 
Consolidated
 
 
(in thousands)
Operating (loss) income
 
$
(19,039
)
 
$
(4,430
)
 
$
8,384

 
$
(8,717
)
 
$
11,387

 
$
(23,413
)
 
$
(35,828
)
Depreciation and amortization
 
9,025

 
25,129

 
4,425

 
10,705

 
416

 
903

 
50,603

Amortization recorded to cost of sales
 
100

 
—

 
195

 
—

 
1,454

 
—

 
1,749

Net unrealized losses (gains) on derivatives
 
1,613

 
(2,193
)
 
2,734

 
139

 
—

 
—

 
2,293

Inventory valuation adjustment
 
—

 
—

 
—

 
—

 
39,530

 
—

 
39,530

Lower of cost or market adjustments
 
—

 
—

 
—

 
—

 
(393
)
 
—

 
(393
)
Loss (gain) on disposal or impairment of assets, net
 
8,477

 
(11
)
 
17

 
(65
)
 
(7,563
)
 
(3
)
 
852

Equity-based compensation expense
 
—

 
—

 
—

 
—

 
—

 
10,660

 
10,660

Acquisition expense
 
—

 
—

 
—

 
—

 
—

 
724

 
724

Other income, net
 
145

 
—

 
24

 
139

 
11

 
1,762

 
2,081

Adjusted EBITDA attributable to unconsolidated entities
 
2,386

 
46

 
—

 
(111
)
 
782

 
—

 
3,103

Adjusted EBITDA attributable to noncontrolling interest
 
—

 
(794
)
 
—

 
19

 
—

 
—

 
(775
)
Other
 
793

 
76

 
20

 
—

 
—

 
—

 
889

Adjusted EBITDA
 
$
3,500

 
$
17,823

 
$
15,799

 
$
2,109

 
$
45,624

 
$
(9,367
)
 
$
75,488


72

 
 
Six Months Ended September 30, 2017
 
 
Crude Oil
Logistics
 
Water
Solutions
 
Liquids
 
Retail
Propane
 
Refined
Products
and
Renewables
 
Corporate
and
Other
 
Consolidated
 
 
(in thousands)
Operating income (loss)
 
$
5,553

 
$
(8,702
)
 
$
(126,879
)
 
$
(15,094
)
 
$
35,538

 
$
(34,185
)
 
$
(143,769
)
Depreciation and amortization
 
41,793

 
49,261

 
12,471

 
23,075

 
648

 
1,839

 
129,087

Amortization recorded to cost of sales
 
169

 
—

 
141

 
—

 
2,781

 
—

 
3,091

Net unrealized losses on derivatives
 
1,511

 
3,022

 
11,313

 
230

 
—

 
—

 
16,076

Inventory valuation adjustment
 
—

 
—

 
—

 
—

 
(21,347
)
 
—

 
(21,347
)
Lower of cost or market adjustments
 
—

 
—

 
—

 
—

 
9,411

 
—

 
9,411

(Gain) loss on disposal or impairment of assets, net
 
(3,716
)
 
185

 
117,729

 
1,096

 
(15,056
)
 
—

 
100,238

Equity-based compensation expense
 
—

 
—

 
—

 
—

 
—

 
14,886

 
14,886

Acquisition expense
 
—

 
—

 
—

 
—

 
—

 
(54
)
 
(54
)
Other income, net
 
94

 
20

 
7

 
251

 
335

 
3,299

 
4,006

Adjusted EBITDA attributable to unconsolidated entities
 
7,620

 
281

 
—

 
(11
)
 
2,107

 
—

 
9,997

Adjusted EBITDA attributable to noncontrolling interest
 
—

 
(434
)
 
—

 
252

 
—

 
—

 
(182
)
Revaluation of liabilities
 
—

 
5,600

 
—

 
—

 
—

 
—

 
5,600

Other
 
2,413

 
185

 
43

 
—

 
—

 
—

 
2,641

Adjusted EBITDA
 
$
55,437

 
$
49,418

 
$
14,825

 
$
9,799

 
$
14,417

 
$
(14,215
)
 
$
129,681

 
 
Six Months Ended September 30, 2016
 
 
Crude Oil
Logistics
 
Water
Solutions
 
Liquids
 
Retail
Propane
 
Refined
Products
and
Renewables
 
Corporate
and
Other
 
Consolidated
 
 
(in thousands)
Operating (loss) income
 
$
(19,664
)
 
$
75,034

 
$
8,327

 
$
(11,219
)
 
$
161,156

 
$
(55,562
)
 
$
158,072

Depreciation and amortization
 
17,993

 
49,563

 
8,874

 
20,392

 
833

 
1,854

 
99,509

Amortization recorded to cost of sales
 
184

 
—

 
390

 
—

 
2,771

 
—

 
3,345

Net unrealized losses (gains) on derivatives
 
219

 
(834
)
 
3,626

 
209

 
—

 
—

 
3,220

Inventory valuation adjustment
 
—

 
—

 
—

 
—

 
32,693

 
—

 
32,693

Lower of cost or market adjustments
 
—

 
—

 
—

 
—

 
108

 
—

 
108

Loss (gain) on disposal or impairment of assets, net
 
9,962

 
(94,281
)
 
49

 
(34
)
 
(119,160
)
 
(3
)
 
(203,467
)
Equity-based compensation expense
 
—

 
—

 
—

 
—

 
—

 
32,994

 
32,994

Acquisition expense
 
—

 
—

 
—

 
2

 
—

 
1,159

 
1,161

Other (expense) income, net
 
(1,310
)
 
310

 
63

 
320

 
2,879

 
3,591

 
5,853

Adjusted EBITDA attributable to unconsolidated entities
 
5,074

 
(63
)
 
—

 
(277
)
 
1,676

 
—

 
6,410

Adjusted EBITDA attributable to noncontrolling interest
 
—

 
(1,631
)
 
—

 
141

 
—

 
—

 
(1,490
)
Other
 
795

 
163

 
40

 
—

 
—

 
—

 
998

Adjusted EBITDA
 
$
13,253

 
$
28,261

 
$
21,369

 
$
9,534

 
$
82,956

 
$
(15,967
)
 
$
139,406


Liquidity, Sources of Capital and Capital Resource Activities

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

73


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

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

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

Under current market conditions, we are much less likely to pursue acquisitions than we have been in the past. We continue to undertake certain capital expansion projects, including the Glass Mountain pipeline extension, among others. We expect to be able to finance these projects through available capacity on our Revolving Credit Facility (as defined herein), asset sales or other forms of financing.

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

Class B Preferred Units

During the six months ended September 30, 2017, we issued 8,400,000 of our 9.00% Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”) representing limited partner interests at a price of $25.00 per unit for net proceeds of $202.8 million (net of the underwriters’ discount of $6.6 million and offering costs of $0.6 million). 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.

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 September 30, 2017, the Credit Agreement includes a revolving credit facility to fund working capital needs, which had a capacity of $1.05 billion for cash borrowings and letters of credit, (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects, which had a capacity of $715.0 million (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). During the three months ended September 30, 2017, we reallocated $50.0 million from the Expansion Capital Facility to the Working Capital Facility. We had letters of credit of $115.1 million on the Working Capital Facility at September 30, 2017.

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

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


74

Senior Secured Notes

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

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

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

Senior Unsecured Notes

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

Repurchases

During the six months ended September 30, 2017, we repurchased $18.7 million of the 2019 Notes, $26.5 million of the 2023 Notes, and $15.7 million of the 2025 Notes. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for a further discussion of the repurchases.

Compliance

At September 30, 2017, we were in compliance with the covenants under the indentures for all of the senior unsecured notes.

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

Revolving Credit Balances

The following table summarizes our Revolving Credit Facility borrowings for the periods indicated:
 
 
Average Balance
Outstanding
 
Lowest
Balance
 
Highest
Balance
 
 
(in thousands)
Six Months Ended September 30, 2017
 
 
 
 
 
 
Expansion capital borrowings
 
$
97,123

 
$
—

 
$
193,500

Working capital borrowings
 
$
783,653

 
$
719,500

 
$
869,500

 
 
 
 
 
 
 
Six Months Ended September 30, 2016
 
 
 
 
 
 
Expansion capital borrowings
 
$
1,258,478

 
$
1,153,500

 
$
1,338,000

Working capital borrowings
 
$
629,292

 
$
465,500

 
$
718,000


At-The-Market Program

On August 24, 2016, we entered into an equity distribution agreement in connection with an at-the-market program (the “ATM Program”) pursuant to which we may issue and sell up to $200.0 million of common units. We are under no obligation to issue equity under the ATM Program. We did not issue any common units under the ATM Program during the six months ended September 30, 2017, and approximately $134.7 million remained available for sale under the ATM Program as of September 30, 2017.


75

Common Unit Repurchase Program

On August 29, 2017, the board of directors of our general partner authorized a common unit repurchase program, under which we may repurchase up to $15.0 million of our outstanding common units through December 31, 2017 from time to time in the open market or in other privately negotiated transactions. During the three months ended September 30, 2017, we repurchased 1,193,635 common units for an aggregate price of $11.2 million, including commissions.

Capital Expenditures

The following table summarizes expansion and maintenance capital expenditures for the periods indicated which excludes additions for tank bottoms and line fill. This information has been prepared on the accrual basis, and excludes property, plant and equipment and intangible assets acquired in acquisitions.
 
 
Capital Expenditures
 
 
Expansion
 
Maintenance
 
Total
 
 
(in thousands)
Three Months Ended September 30,
 
 
 
 
 
 
2017
 
$
19,439

 
$
7,994

 
$
27,433

2016
 
$
48,781

 
$
6,401

 
$
55,182

 
 
 
 
 
 
 
Six Months Ended September 30,
 
 
 
 
 
 
2017
 
$
44,032

 
$
14,521

 
$
58,553

2016
 
$
143,884

 
$
12,696

 
$
156,580


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

Cash Flows

The following table summarizes the sources (uses) of our cash flows for the periods indicated:
 
 
Six Months Ended September 30,
Cash Flows Provided by (Used in)
 
2017
 
2016
 
 
(in thousands)
Operating activities, before changes in operating assets and liabilities
 
$
65,847

 
$
78,731

Changes in operating assets and liabilities
 
(55,893
)
 
(133,608
)
Operating activities
 
$
9,954

 
$
(54,877
)
Investing activities
 
$
(108,212
)
 
$
(235,542
)
Financing activities
 
$
104,401

 
$
285,670


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

76

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

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

•
a decrease in capital expenditures from $201.6 million during the six months ended September 30, 2016, primarily related to the Grand Mesa Pipeline, to $56.5 million during the six months ended September 30, 2017;
•
a $64.9 million decrease in cash paid for acquisitions during the six months ended September 30, 2017;
•
a $24.2 million increase in proceeds primarily from the sale of excess pipe in our Crude Oil Logistics segment during the six months ended September 30, 2017; and
•
a $16.9 million payment to terminate a development agreement during the six months ended September 30, 2016.

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

•
$112.4 million in proceeds received from the sale of the TLP common units we owned during the six months ended September 30, 2016; and
•
$14.2 million of investments in unconsolidated entities during the six months ended September 30, 2017.

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

•
an increase of $100.3 million in repurchases of a portion of our outstanding senior secured notes and senior unsecured notes during the six months ended September 30, 2017;
•
a decrease of $32.3 million in proceeds received from the sale of preferred units;
•
an increase of $24.0 million in distributions paid to our general and common unit partners, preferred unitholders and noncontrolling interest owners during the six months ended September 30, 2017;
•
a decrease of $17.5 million in borrowings on our Revolving Credit Facility (net of repayments) during the six months ended September 30, 2017;
•
$11.7 million for the repurchase of a portion of our common units during the six months ended September 30, 2017; and
•
$10.5 million for the repurchase of warrants related to our Class A Preferred Units during the six months ended September 30, 2017.

These decreases in net cash provided by financing activities were partially offset by a $25.8 million release of contingent consideration liabilities related to the termination of a development agreement during the six months ended September 30, 2016.

Distributions Declared

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

On September 18, 2017, the board of directors of our general partner declared a distribution for the three months ended September 30, 2017 of $5.7 million, which was paid to the holders of the Class B Preferred Units on October 16, 2017.

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

77

Class A Preferred Units of $6.4 million in the aggregate. The distributions to both the common unitholders and the holders of the Class A Preferred Units are to be paid on November 14, 2017.

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

Contractual Obligations

The following table summarizes our contractual obligations at September 30, 2017 for our fiscal years ending thereafter:
 
 
 
 
Six Months Ending March 31,
 
Fiscal Year Ending March 31,
 
 
 
 
Total
 
2018
 
2019
 
2020
 
2021
 
2022
 
Thereafter
 
 
(in thousands)
Principal payments on long-term debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expansion capital borrowings
 
$
102,000

 
$
—

 
$
—

 
$
—

 
$
—

 
$
102,000

 
$
—

Working capital borrowings
 
869,500

 
—

 
—

 
—

 
—

 
869,500

 
—

Senior secured notes
 
195,000

 
19,500

 
39,000

 
39,000

 
39,000

 
39,000

 
19,500

Senior unsecured notes
 
1,885,672

 
—

 
—

 
360,781

 
—

 
367,048

 
1,157,843

Other long-term debt
 
12,756

 
1,793

 
2,895

 
2,285

 
5,450

 
274

 
59

Interest payments on long-term debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revolving Credit Facility (1)
 
214,743

 
38,001

 
49,095

 
49,095

 
49,095

 
29,457

 
—

Senior secured notes
 
34,178

 
7,918

 
10,374

 
7,781

 
5,187

 
2,594

 
324

Senior unsecured notes
 
701,364

 
61,952

 
123,904

 
114,659

 
105,414

 
105,414

 
190,021

Other long-term debt
 
1,581

 
336

 
525

 
369

 
185

 
43

 
123

Letters of credit
 
115,099

 
—

 
—

 
—

 
—

 
115,099

 
—

Future minimum lease payments under noncancelable operating leases
 
553,578

 
71,787

 
120,589

 
107,255

 
94,118

 
65,985

 
93,844

Future minimum throughput payments under noncancelable agreements (2)
 
120,394

 
26,001

 
52,042

 
42,351

 
—

 
—

 
—

Construction commitments (3)
 
24,470

 
24,026

 
444

 
—

 
—

 
—

 
—

Fixed-price commodity purchase commitments:
 

 
 
 
 
 
 
 
 
 
 
 
 
Crude oil
 
161,432

 
161,432

 
—

 
—

 
—

 
—

 
—

Natural gas liquids
 
46,156

 
44,816

 
1,340

 
—

 
—

 
—

 
—

Index-price commodity purchase commitments (4):
 

 
 
 
 
 
 
 
 
 
 
 
 
Crude oil (5)
 
1,770,080

 
576,009

 
524,256

 
412,569

 
161,485

 
95,761

 
—

Natural gas liquids
 
601,243

 
563,817

 
37,426

 
—

 
—

 
—

 
—

Total contractual obligations
 
$
7,409,246

 
$
1,597,388

 
$
961,890

 
$
1,136,145

 
$
459,934

 
$
1,792,175

 
$
1,461,714

 
(1)
The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at September 30, 2017. See Note 8 to our unaudited condensed consolidated financial statements included in this Quarterly Report for additional information on our Credit Agreement.
(2)
We have executed noncancelable agreements with crude oil operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity. Under certain agreements we have the ability to recover minimum shipping fees previously paid if our shipping volumes exceed the minimum monthly shipping commitment during each month remaining under the agreement. See Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report for additional information.
(3)
At September 30, 2017, construction commitments primarily relate to the Glass Mountain pipeline extension.
(4)
Index prices are based on a forward price curve at September 30, 2017. A theoretical change of $0.10 per gallon of natural gas liquids in the underlying commodity price at September 30, 2017 would result in a change of $67.0 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel of crude oil in the underlying commodity price at September 30, 2017 would result in a change of $39.1 million in the value of our index-price crude oil purchase commitments. See Note 9 to our unaudited condensed consolidated financial statements included in this Quarterly Report for further detail of the commitments.

78

(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.


79

 
Item 3.    Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

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

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At September 30, 2017, we had $971.5 million of outstanding borrowings under our Revolving Credit Facility at a weighted average interest rate of 4.50%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.2 million, based on borrowings outstanding at September 30, 2017.

Commodity Price and Credit Risk

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

Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions. At September 30, 2017, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.

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

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

Although we use financial derivative instruments to reduce the market price risk associated with forecasted transactions, we do not account for financial derivative transactions as hedges. We record the changes in fair value of these financial derivative transactions within cost of sales in our unaudited condensed consolidated statements of operations. The following table summarizes the hypothetical impact on the September 30, 2017 fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands):
 
Increase
(Decrease)
To Fair Value
Crude oil (Crude Oil Logistics segment)
$
(5,451
)
Propane (Liquids segment)
$
1,404

Other products (Liquids segment)
$
(14,458
)
Gasoline (Refined Products and Renewables segment)
$
(15,196
)
Diesel (Refined Products and Renewables segment)
$
(4,990
)
Ethanol (Refined Products and Renewables segment)
$
(2,753
)
Biodiesel (Refined Products and Renewables segment)
$
124

Canadian dollars (Liquids segment)
$
711



80

Fair Value

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

Item 4.
Controls and Procedures

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

We completed an evaluation under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures at September 30, 2017. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of September 30, 2017, such disclosure controls and procedures were effective to provide the reasonable assurance described above.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) of the Exchange Act) during the three months ended September 30, 2017 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.


81

PART II - OTHER INFORMATION

Item 1.    Legal Proceedings

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

Item 1A.    Risk Factors

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

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

Common Unit Repurchase Program

On August 29, 2017, the board of directors of our general partner authorized a common unit repurchase program, under which we may repurchase up to $15.0 million of our outstanding common units through December 31, 2017 from time to time in the open market or in other privately negotiated transactions. The common unit repurchase program authorization does not obligate us to repurchase any dollar amount or number of our common units. The following table summarizes the repurchase of common units during the three months ended September 30, 2017:
 
 
 
 
 
 
Total Number of
 
 
 
 
 
 
 
 
Common Units
 
Approximate Dollar Value
 
 
Total Number of
 
Average Price
 
Purchased as Part
 
of Common Units
 
 
Common Units
 
Paid Per
 
of Publicly Announced
 
that May Yet Be Purchased
Period
 
Purchased
 
Common Unit
 
Program
 
Under the Program
July 1-31, 2017
 
37,554

 
$
13.58

 
—

 
$
—

August 1-31, 2017
 
227,192

 
$
9.00

 
227,192

 
$
12,948,047

September 1-30, 2017
 
966,443

 
$
9.39

 
966,443

 
$
3,847,062

Total
 
1,231,189

 
 
 
1,193,635

 
$
3,847,062


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

Item 3.    Defaults Upon Senior Securities

Not applicable.

Item 4.    Mine Safety Disclosures

Not applicable.

Item 5.    Other Information

None.


82

Item 6.    Exhibits
Exhibit Number
 
Exhibit
4.1
 
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 September 30, 2017 and March 31, 2017, (ii) Unaudited Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2017 and 2016, (iii) Unaudited Condensed Consolidated Statements of Comprehensive (Loss) Income for the three months and six months ended September 30, 2017 and 2016, (iv) Unaudited Condensed Consolidated Statement of Changes in Equity for the six months ended September 30, 2017, (v) Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 2017 and 2016, and (vi) Notes to Unaudited Condensed Consolidated Financial Statements.


83

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
NGL ENERGY PARTNERS LP
 
 
 
 
By:
NGL Energy Holdings LLC, its general partner
 
 
 
Date: November 7, 2017
 
By:
/s/ H. Michael Krimbill
 
 
 
H. Michael Krimbill
 
 
 
Chief Executive Officer
 
 
 
Date: November 7, 2017
 
By:
/s/ Robert W. Karlovich III
 
 
 
Robert W. Karlovich III
 
 
 
Chief Financial Officer


84

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