Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10–Q

 

(Mark One)

 

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

 

For the quarterly period ended September 30, 2015

 

or

 

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

 

For the transition period from                              to                              

 

Commission File Number: 001-35172

 

NGL Energy Partners LP

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware

 

27-3427920

(State or Other Jurisdiction of Incorporation or
Organization)

 

(I.R.S. Employer Identification No.)

 

 

 

6120 South Yale Avenue
Suite 805
Tulsa, Oklahoma

 

74136

(Address of Principal Executive Offices)

 

(Zip code)

 

(918) 481–1119

(Registrant’s Telephone Number, Including Area Code)

 

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

 

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

 

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

 

Large accelerated filer x

 

Accelerated filer o

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

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

 

At November 2, 2015, there were 106,936,303 common units issued and outstanding.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

PART I

 

 

 

Item 1.

Financial Statements (Unaudited)

3

 

 

 

 

Condensed Consolidated Balance Sheets at September 30, 2015 and March 31, 2015

3

 

 

 

 

Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2015 and 2014

4

 

 

 

 

Condensed Consolidated Statements of Comprehensive Loss for the three months and six months ended September 30, 2015 and 2014

5

 

 

 

 

Condensed Consolidated Statement of Changes in Equity for the six months ended September 30, 2015

6

 

 

 

 

Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 2015 and 2014

7

 

 

 

 

Notes to Condensed Consolidated Financial Statements

8

 

 

 

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

53

 

 

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

100

 

 

 

Item 4.

Controls and Procedures

101

 

 

 

PART II

 

 

 

Item 1.

Legal Proceedings

102

 

 

 

Item 1A.

Risk Factors

102

 

 

 

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

102

 

 

 

Item 3.

Defaults Upon Senior Securities

102

 

 

 

Item 4.

Mine Safety Disclosures

102

 

 

 

Item 5.

Other Information

102

 

 

 

Item 6.

Exhibits

103

 

 

 

Signatures

104

 

 

Index to Exhibits

105

 

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Forward-Looking Statements

 

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

 

·                   the prices of crude oil, natural gas liquids, refined products, ethanol, and biodiesel;

 

·                   energy prices generally;

 

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

 

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

 

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

 

·                   the level of crude oil and natural gas drilling and production in producing areas in which we have water treatment and disposal facilities;

 

·                   the prices of propane and distillates relative to the prices of alternative and competing fuels;

 

·                   the price of gasoline relative to the price of corn, which impacts the price of ethanol;

 

·                   the ability to obtain adequate supplies of products in the event of an interruption in supply or transportation and the availability of capacity to transport products to market areas;

 

·                   actions taken by foreign oil and gas producing nations;

 

·                   the political and economic stability of foreign oil and gas producing nations;

 

·                   the effect of weather conditions on supply and demand for crude oil, natural gas liquids, refined products, ethanol, and biodiesel;

 

·                   the effect of natural disasters, lightning strikes, or other significant weather events;

 

·                   the availability of local, intrastate and interstate transportation infrastructure, including with respect to our truck, railcar, and barge transportation services;

 

·                   the availability, price, and marketing of competing fuels;

 

·                   the impact of energy conservation efforts on product demand;

 

·                   energy efficiencies and technological trends;

 

·                   governmental regulation and taxation;

 

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

 

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

 

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·                   the maturity of the crude oil, natural gas liquids, and refined products industries and competition from other marketers;

 

·                   loss of key personnel;

 

·                   the ability to hire drivers;

 

·                   the ability to renew contracts with key customers;

 

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

 

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

 

·                   the nonpayment or nonperformance by our counterparties;

 

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

 

·                   a deterioration of the credit and capital markets;

 

·                   the ability to successfully identify and consummate strategic acquisitions, and integrate acquired assets and businesses;

 

·                   changes in the volume of hydrocarbons recovered during the wastewater treatment process;

 

·                   changes in the financial condition and results of operations of entities in which we own noncontrolling equity interests;

 

·                   changes in applicable laws and regulations, including tax, environmental, transportation and employment regulations, or new interpretations by regulatory agencies concerning such laws and regulations and the impact of such laws and regulations (now existing or in the future) on our business operations;

 

·                   the costs and effects of legal and administrative proceedings;

 

·                   any reduction or the elimination of the federal Renewable Fuel Standard; and

 

·                   changes in the jurisdictional characteristics of, or the applicable regulatory policies with respect to, our pipeline assets.

 

You should not put undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date of this Quarterly Report. Except as required by state and federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events, or otherwise. When considering forward-looking statements, please review the risks described under Part I, Item 1A—“Risk Factors” in our Annual Report on Form 10—K for the fiscal year ended March 31, 2015.

 

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PART I

 

Item 1.    Financial Statements (Unaudited)

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Balance Sheets

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

 

 

 

September 30,

 

March 31,

 

 

 

2015

 

2015

 

ASSETS

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

 

$

30,053

 

$

41,303

 

Accounts receivable–trade, net of allowance for doubtful accounts of $5,995 and $4,367, respectively

 

712,025

 

1,024,226

 

Accounts receivable–affiliates

 

6,345

 

17,198

 

Inventories

 

408,374

 

441,762

 

Prepaid expenses and other current assets

 

120,122

 

120,855

 

Total current assets

 

1,276,919

 

1,645,344

 

 

 

 

 

 

 

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $270,332 and $202,959, respectively

 

1,845,112

 

1,617,389

 

GOODWILL

 

1,490,928

 

1,402,761

 

INTANGIBLE ASSETS, net of accumulated amortization of $274,823 and $220,517, respectively

 

1,231,192

 

1,288,343

 

INVESTMENTS IN UNCONSOLIDATED ENTITIES

 

473,239

 

472,673

 

LOAN RECEIVABLE–AFFILIATE

 

23,775

 

8,154

 

OTHER NONCURRENT ASSETS

 

108,672

 

112,837

 

Total assets

 

$

6,449,837

 

$

6,547,501

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Accounts payable–trade

 

$

568,523

 

$

833,380

 

Accounts payable–affiliates

 

18,794

 

25,794

 

Accrued expenses and other payables

 

164,433

 

195,116

 

Advance payments received from customers

 

96,380

 

54,234

 

Current maturities of long-term debt

 

4,040

 

4,472

 

Total current liabilities

 

852,170

 

1,112,996

 

 

 

 

 

 

 

LONG-TERM DEBT, net of current maturities

 

3,093,694

 

2,745,299

 

OTHER NONCURRENT LIABILITIES

 

17,679

 

16,086

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 10)

 

 

 

 

 

 

 

 

 

 

 

EQUITY:

 

 

 

 

 

General partner, representing a 0.1% interest, 105,269 and 103,899 notional units, respectively

 

(34,380

)

(37,021

)

Limited partners, representing a 99.9% interest, 105,164,071 and 103,794,870 common units issued and outstanding, respectively

 

1,976,663

 

2,162,924

 

Accumulated other comprehensive loss

 

(136

)

(109

)

Noncontrolling interests

 

544,147

 

547,326

 

Total equity

 

2,486,294

 

2,673,120

 

Total liabilities and equity

 

$

6,449,837

 

$

6,547,501

 

 

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

 

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Operations

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

 

 

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

REVENUES:

 

 

 

 

 

 

 

 

 

Crude oil logistics

 

$

1,007,578

 

$

2,111,143

 

$

2,335,362

 

$

4,040,426

 

Water solutions

 

47,494

 

52,719

 

101,787

 

100,033

 

Liquids

 

258,992

 

539,753

 

507,977

 

1,014,910

 

Retail propane

 

53,206

 

68,358

 

117,653

 

146,260

 

Refined products and renewables

 

1,825,925

 

2,607,220

 

3,668,885

 

3,724,717

 

Other

 

 

1,333

 

 

2,794

 

Total Revenues

 

3,193,195

 

5,380,526

 

6,731,664

 

9,029,140

 

 

 

 

 

 

 

 

 

 

 

COST OF SALES:

 

 

 

 

 

 

 

 

 

Crude oil logistics

 

982,719

 

2,083,712

 

2,274,711

 

3,981,351

 

Water solutions

 

(8,567

)

(9,439

)

(4,960

)

1,134

 

Liquids

 

221,115

 

514,064

 

453,391

 

976,080

 

Retail propane

 

20,879

 

39,894

 

50,443

 

87,418

 

Refined products and renewables

 

1,789,680

 

2,550,851

 

3,554,792

 

3,665,164

 

Other

 

 

383

 

 

2,371

 

Total Cost of Sales

 

3,005,826

 

5,179,465

 

6,328,377

 

8,713,518

 

 

 

 

 

 

 

 

 

 

 

OPERATING COSTS AND EXPENSES:

 

 

 

 

 

 

 

 

 

Operating

 

99,773

 

97,419

 

207,687

 

164,855

 

General and administrative

 

29,298

 

41,639

 

91,779

 

69,512

 

Depreciation and amortization

 

56,761

 

50,099

 

116,592

 

89,474

 

Loss on disposal or impairment of assets, net

 

1,291

 

4,134

 

1,712

 

4,566

 

Operating Income (Loss)

 

246

 

7,770

 

(14,483

)

(12,785

)

 

 

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

 

Equity in earnings of unconsolidated entities

 

2,432

 

3,697

 

11,150

 

6,262

 

Interest expense

 

(31,571

)

(28,651

)

(62,373

)

(49,145

)

Other income (expense), net

 

1,955

 

(617

)

780

 

(1,008

)

Loss Before Income Taxes

 

(26,938

)

(17,801

)

(64,926

)

(56,676

)

 

 

 

 

 

 

 

 

 

 

INCOME TAX BENEFIT

 

2,786

 

1,922

 

2,248

 

887

 

 

 

 

 

 

 

 

 

 

 

Net Loss

 

(24,152

)

(15,879

)

(62,678

)

(55,789

)

 

 

 

 

 

 

 

 

 

 

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER

 

(16,166

)

(11,056

)

(31,525

)

(20,437

)

 

 

 

 

 

 

 

 

 

 

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

 

(2,891

)

(3,345

)

(6,766

)

(3,410

)

 

 

 

 

 

 

 

 

 

 

NET LOSS ALLOCATED TO LIMITED PARTNERS

 

$

(43,209

)

$

(30,280

)

$

(100,969

)

$

(79,636

)

 

 

 

 

 

 

 

 

 

 

BASIC AND DILUTED LOSS PER COMMON UNIT

 

$

(0.41

)

$

(0.34

)

$

(0.97

)

$

(0.93

)

 

 

 

 

 

 

 

 

 

 

BASIC AND DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING

 

105,189,463

 

88,331,653

 

104,542,427

 

81,267,742

 

 

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

 

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Comprehensive Loss

(U.S. Dollars in Thousands)

 

 

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

$

(24,152

)

$

(15,879

)

$

(62,678

)

$

(55,789

)

Other comprehensive income (loss)

 

(19

)

(22

)

(27

)

163

 

Comprehensive loss

 

$

(24,171

)

$

(15,901

)

$

(62,705

)

$

(55,626

)

 

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

 

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statement of Changes in Equity

Six Months Ended September 30, 2015

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

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

Limited Partners

 

Other

 

 

 

 

 

 

 

General

 

Common

 

 

 

Comprehensive

 

Noncontrolling

 

Total

 

 

 

Partner

 

Units

 

Amount

 

Loss

 

Interests

 

Equity

 

BALANCES AT MARCH 31, 2015

 

$

(37,021

)

103,794,870

 

$

2,162,924

 

$

(109

)

$

547,326

 

$

2,673,120

 

Distributions

 

(28,929

)

 

(125,895

)

 

(17,780

)

(172,604

)

Contributions

 

45

 

 

 

 

6,613

 

6,658

 

Business combinations

 

 

386,383

 

11,367

 

 

 

11,367

 

Equity issued pursuant to incentive compensation plan

 

 

1,140,444

 

32,919

 

 

 

32,919

 

Common unit repurchases

 

 

(157,626

)

(3,650

)

 

 

(3,650

)

Net income (loss)

 

31,525

 

 

(100,969

)

 

6,766

 

(62,678

)

Other comprehensive loss

 

 

 

 

(27

)

 

(27

)

TLP equity-based compensation

 

 

 

 

 

1,301

 

1,301

 

Other

 

 

 

(33

)

 

(79

)

(112

)

BALANCES AT SEPTEMBER 30, 2015

 

$

(34,380

)

105,164,071

 

$

1,976,663

 

$

(136

)

$

544,147

 

$

2,486,294

 

 

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

 

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Cash Flows

(U.S. Dollars in Thousands)

 

 

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

OPERATING ACTIVITIES:

 

 

 

 

 

Net loss

 

$

(62,678

)

$

(55,789

)

Adjustments to reconcile net loss to net cash provided by (used in) operating activities:

 

 

 

 

 

Depreciation and amortization, including amortization of debt issuance costs

 

124,551

 

97,624

 

Non-cash equity-based compensation expense

 

51,482

 

11,758

 

Loss on disposal or impairment of assets, net

 

1,712

 

4,566

 

Provision for doubtful accounts

 

3,046

 

1,347

 

Net commodity derivative gain

 

(44,534

)

(38,496

)

Equity in earnings of unconsolidated entities

 

(11,150

)

(6,262

)

Distributions of earnings from unconsolidated entities

 

11,593

 

5,180

 

Other

 

(8

)

(837

)

Changes in operating assets and liabilities, exclusive of acquisitions:

 

 

 

 

 

Accounts receivable–trade

 

311,377

 

(358,497

)

Accounts receivable–affiliates

 

10,853

 

(33,733

)

Inventories

 

34,333

 

(203,965

)

Prepaid expenses and other assets

 

(7,322

)

(56,109

)

Accounts payable–trade

 

(265,322

)

463,767

 

Accounts payable–affiliates

 

(7,000

)

8,392

 

Accrued expenses and other liabilities

 

(17,083

)

25,719

 

Advance payments received from customers

 

40,245

 

73,700

 

Net cash provided by (used in) operating activities

 

174,095

 

(61,635

)

 

 

 

 

 

 

INVESTING ACTIVITIES:

 

 

 

 

 

Purchases of long-lived assets

 

(222,276

)

(82,851

)

Acquisitions of businesses, including acquired working capital, net of cash acquired

 

(150,546

)

(658,764

)

Cash flows from commodity derivatives

 

43,032

 

4,327

 

Proceeds from sales of assets

 

3,567

 

8,741

 

Investments in unconsolidated entities

 

(6,926

)

(26,390

)

Distributions of capital from unconsolidated entities

 

8,207

 

4,649

 

Loan for natural gas liquids facility

 

(3,913

)

 

Payments on loan for natural gas liquids facility

 

3,546

 

 

Loan to affiliate

 

(15,621

)

 

Net cash used in investing activities

 

(340,930

)

(750,288

)

 

 

 

 

 

 

FINANCING ACTIVITIES:

 

 

 

 

 

Proceeds from borrowings under revolving credit facilities

 

1,354,700

 

1,979,500

 

Payments on revolving credit facilities

 

(1,006,600

)

(1,804,000

)

Issuance of notes

 

 

400,000

 

Payments on other long-term debt

 

(2,344

)

(4,175

)

Debt issuance costs

 

(1,380

)

(9,198

)

Contributions from general partner

 

45

 

395

 

Contributions from noncontrolling interest owners

 

6,613

 

 

Distributions to partners

 

(154,824

)

(111,008

)

Distributions to noncontrolling interest owners

 

(17,780

)

(8,654

)

Taxes paid on behalf of equity incentive plan participants

 

(19,083

)

 

Common unit repurchases

 

(3,650

)

 

Proceeds from sale of common units, net of offering costs

 

 

370,446

 

Other

 

(112

)

 

Net cash provided by financing activities

 

155,585

 

813,306

 

Net increase (decrease) in cash and cash equivalents

 

(11,250

)

1,383

 

Cash and cash equivalents, beginning of period

 

41,303

 

10,440

 

Cash and cash equivalents, end of period

 

$

30,053

 

$

11,823

 

 

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

 

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

Note 1—Organization and Operations

 

NGL Energy Partners LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At September 30, 2015, our operations include:

 

·                   Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals, owned and leased pipeline injection stations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned and leased barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

 

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

 

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

 

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

 

·                   Our refined products and renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the 2.0% general partner interest and a 19.6% limited partner interest in TransMontaigne Partners L.P. (“TLP”), which conducts refined products terminaling, storage, and transportation operations.

 

Note 2—Significant Accounting Policies

 

Basis of Presentation

 

The accompanying unaudited condensed consolidated financial statements include our accounts and those of our controlled subsidiaries. All significant intercompany transactions and account balances have been eliminated in consolidation. Investments we cannot exercise control of, but can exercise significant influence over, are accounted for using the equity method of accounting.

 

Our unaudited condensed consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim consolidated financial information in accordance with the rules and regulations of the Securities and Exchange Commission. Accordingly, the unaudited condensed consolidated financial statements exclude certain information and notes required by GAAP for complete annual consolidated financial statements. However, we believe that the disclosures made are adequate to make the information presented not misleading. The unaudited condensed consolidated financial statements include all adjustments that we consider necessary for a fair presentation of our consolidated financial position and results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed in this Quarterly Report. The unaudited condensed consolidated balance sheet at March 31, 2015 is derived from our audited consolidated financial statements for the fiscal year ended March 31, 2015 included in our Annual Report on Form 10–K (“Annual Report”).

 

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

 

These interim unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report. Due to the seasonal nature of certain of our operations and other factors, the results of operations for interim periods are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2016.

 

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Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

Use of Estimates

 

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

 

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

 

Significant Accounting Policies

 

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

 

Fair Value Measurements

 

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

 

·                   Level 1—Quoted prices in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

 

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

 

·                   Level 3—Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

 

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

 

Revenue Recognition

 

We record product sales revenues when title to the product transfers to the purchaser, which typically occurs when the purchaser receives the product. We record terminaling, transportation, storage, and service revenues when the service is performed, and we record tank and other rental revenues over the lease term. Several of our terminaling service agreements with throughput customers allow us to receive the product volume gained resulting from differences between the measurement of product volumes received and distributed at our terminaling facilities. Such differences are due to the inherent variances in measurement devices and methodology. We record revenues for the net proceeds from the sale of the product gained. Revenues for our water solutions segment are recognized when we obtain the wastewater at our treatment and disposal facilities.

 

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Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. We include amounts billed to customers for shipping and handling costs in revenues in our condensed consolidated statements of operations.

 

We enter into certain contracts whereby we agree to purchase product from a counterparty and sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into at the same time and are entered into in contemplation of each other, we record the revenues for these transactions net of cost of sales.

 

Revenues during the three months and six months ended September 30, 2015 include $1.5 million and $2.9 million, respectively, associated with the amortization of a liability recorded in the acquisition accounting for an acquired business related to certain out-of-market revenue contracts.

 

Supplemental Cash Flow Information

 

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

 

 

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

(in thousands)

 

Interest paid, exclusive of debt issuance costs and letter of credit fees

 

$

26,323

 

$

10,445

 

$

57,495

 

$

36,429

 

Income taxes paid

 

$

533

 

$

1,241

 

$

4,616

 

$

2,246

 

 

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

 

Inventories

 

We value our inventories at the lower of cost or market, with cost determined using either the weighted-average cost or the first in, first out (FIFO) methods, including the cost of transportation and storage. Market is determined based on estimated replacement cost using prices at the end of the reporting period. In performing this analysis, we consider fixed-price forward commitments and the opportunity to transfer propane inventory from our wholesale liquids business to our retail propane business to sell the inventory in retail markets.

 

Inventories consist of the following at the dates indicated:

 

 

 

September 30,

 

March 31,

 

 

 

2015

 

2015

 

 

 

(in thousands)

 

Crude oil

 

$

84,672

 

$

145,412

 

Natural gas liquids–

 

 

 

 

 

Propane

 

65,124

 

44,535

 

Butane

 

22,715

 

8,668

 

Other

 

7,028

 

3,874

 

Refined products–

 

 

 

 

 

Gasoline

 

99,208

 

128,092

 

Diesel

 

97,016

 

59,097

 

Renewables

 

22,484

 

44,668

 

Other

 

10,127

 

7,416

 

Total

 

$

408,374

 

$

441,762

 

 

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Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

Investments in Unconsolidated Entities

 

We own noncontrolling interests in certain entities. The largest of these investments are in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oil pipeline in Oklahoma, and Battleground Oil Specialty Terminal Company LLC (“BOSTCO”), which owns a refined products storage facility.

 

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

 

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

 

 

 

 

 

Ownership

 

Date Acquired

 

September 30,

 

March 31,

 

Entity

 

Segment

 

Interest

 

or Formed

 

2015

 

2015

 

 

 

 

 

 

 

 

 

(in thousands)

 

Glass Mountain (1)

 

Crude oil logistics

 

50.0

%

December 2013

 

$

183,888

 

$

187,590

 

BOSTCO (2)

 

Refined products and renewables

 

42.5

%

July 2014

 

238,687

 

238,146

 

Frontera (2)

 

Refined products and renewables

 

50.0

%

July 2014

 

17,069

 

16,927

 

Water supply company

 

Water solutions

 

35.0

%

June 2014

 

16,483

 

16,471

 

Water treatment and disposal facility

 

Water solutions

 

50.0

%

August 2015

 

2,290

 

 

Ethanol production facility

 

Refined products and renewables

 

19.0

%

December 2013

 

14,231

 

13,539

 

Retail propane company

 

Retail propane

 

50.0

%

April 2015

 

591

 

 

Total

 

 

 

 

 

 

 

$

473,239

 

$

472,673

 

 


(1)   When we acquired Gavilon, LLC, we recorded the investment in Glass Mountain at fair value. Our investment in Glass Mountain exceeds our proportionate share of the historical net book value of Glass Mountain’s net assets by $75.7 million at September 30, 2015. This difference relates primarily to goodwill and customer relationships.

 

(2)   When we acquired TransMontaigne Inc. (“TransMontaigne”), we recorded the investments in BOSTCO and Frontera Brownsville LLC (“Frontera”) at fair value. On a combined basis, our investments in BOSTCO and Frontera exceed our proportionate share of the historical net book value of BOSTCO’s and Frontera’s net assets by $15.4 million at September 30, 2015. This difference relates primarily to goodwill.

 

Other Noncurrent Assets

 

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

 

 

 

September 30,

 

March 31,

 

 

 

2015

 

2015

 

 

 

(in thousands)

 

Loan receivable (1)

 

$

54,413

 

$

58,050

 

Linefill (2)

 

35,060

 

35,060

 

Other

 

19,199

 

19,727

 

Total

 

$

108,672

 

$

112,837

 

 


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

 

(2)          Represents minimum volumes of crude oil we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At September 30, 2015, linefill consisted of 487,104 barrels of crude oil.

 

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

Accrued Expenses and Other Payables

 

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

 

 

 

September 30,

 

March 31,

 

 

 

2015

 

2015

 

 

 

(in thousands)

 

Accrued compensation and benefits

 

$

40,339

 

$

52,078

 

Excise and other tax liabilities

 

39,941

 

43,847

 

Derivative liabilities

 

13,729

 

27,950

 

Accrued interest

 

22,369

 

23,065

 

Product exchange liabilities

 

25,441

 

15,480

 

Other

 

22,614

 

32,696

 

Total

 

$

164,433

 

$

195,116

 

 

Noncontrolling Interests

 

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

 

As part of our acquisition of TransMontaigne on July 1, 2014, we acquired a 19.7% limited partner interest in TLP. We attribute net earnings allocable to TLP’s limited partners to the controlling and noncontrolling interests based on the relative ownership interests in TLP as well as including certain adjustments related to our acquisition accounting. Earnings allocable to TLP’s limited partners are net of the earnings allocable to TLP’s general partner interest. The earnings allocable to TLP’s general partner interest include the distributions of cash attributable to the period to TLP’s general partner interest and incentive distribution rights, net of adjustments for TLP’s general partner’s proportionate share of undistributed earnings. Undistributed earnings are allocated to TLP’s limited partners and TLP’s general partner interest based on their respective sharing of earnings or losses specified in TLP’s partnership agreement, which is based on their ownership percentages of 98% and 2%, respectively.

 

Business Combination Measurement Period

 

We record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Pursuant to GAAP, an entity is allowed no more than one year to obtain the information necessary to identify and measure the fair values of the assets acquired and liabilities assumed in a business combination. As described in Note 4, certain acquisitions are still within this measurement period, and as a result, the acquisition date fair values we have recorded for the assets acquired and liabilities assumed are subject to change.

 

Recent Accounting Pronouncements

 

In July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015–11, “Simplifying the Measurement of Inventory.” ASU No. 2015–11 requires that inventory within the scope of the guidance be measured at the lower of cost or net realizable value. The ASU is effective for the Partnership beginning April 1, 2017, although early adoption is permitted. We do not expect the adoption of this ASU to have a material impact on our current accounting policies.

 

In April 2015, the FASB issued ASU No. 2015–03, “Simplifying the Presentation of Debt Issuance Costs.” ASU No. 2015–03 requires that debt issuance costs (excluding costs associated with revolving debt arrangements) be presented in the balance sheet as a reduction to the carrying amount of the debt. We plan to adopt this ASU effective March 31, 2016, when we will begin presenting

 

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Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

debt issuance costs as a reduction to long-term debt, rather than as an intangible asset. At September 30, 2015, intangible assets on our condensed consolidated balance sheet include $16.1 million of debt issuance costs associated with our senior notes that, upon adoption of ASU No. 2015–03, would be reclassified as a reduction to long-term debt. The ASU requires retrospective application for all prior periods presented. At March 31, 2015, intangible assets on our condensed consolidated balance sheet include $17.8 million of debt issuance costs associated with our senior notes that, upon adoption of ASU No. 2015–03, will be reclassified as a reduction to long-term debt.

 

In May 2014, the FASB issued ASU No. 2014–09, “Revenue from Contracts with Customers.” ASU No. 2014–09 will replace most existing revenue recognition guidance in GAAP. The core principle of this ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU is effective for the Partnership beginning April 1, 2018, and allows for both full retrospective and modified retrospective (with cumulative effect) methods of adoption. We are in the process of determining the method of adoption and assessing the impact of this ASU on our consolidated financial statements.

 

Note 3—Loss Per Common Unit

 

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

 

 

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

(in thousands, except unit and per unit amounts)

 

Net loss attributable to parent equity

 

$

(27,043

)

$

(19,224

)

$

(69,444

)

$

(59,199

)

Less: Net income allocated to general partner (1)

 

(16,166

)

(11,056

)

(31,525

)

(20,437

)

Less: Net loss allocated to subordinated unitholders (2)

 

 

 

 

4,013

 

Net loss allocated to common unitholders

 

$

(43,209

)

$

(30,280

)

$

(100,969

)

$

(75,623

)

 

 

 

 

 

 

 

 

 

 

Basic and diluted weighted average common units outstanding

 

105,189,463

 

88,331,653

 

104,542,427

 

81,267,742

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted loss per common unit

 

$

(0.41

)

$

(0.34

)

$

(0.97

)

$

(0.93

)

 


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

 

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

 

The restricted units described in Note 11 were antidilutive during the three months and six months ended September 30, 2015 and 2014, but could have an impact on earnings per unit in future periods.

 

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Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

Note 4—Acquisitions

 

Year Ending March 31, 2016

 

Delaware Basin Water Solutions Facilities

 

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

 

Property, plant and equipment:

 

 

 

Water treatment facilities and equipment (3–30 years)

 

$

18,650

 

Land

 

400

 

Goodwill

 

12,776

 

Intangible asset:

 

 

 

Customer relationships (6 years)

 

16,000

 

Investments in unconsolidated entities

 

2,290

 

Accrued expenses and other payables

 

(116

)

Fair value of net assets acquired

 

$

50,000

 

 

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

 

Water Solutions Facilities

 

As described below, we are party to certain development agreements that provide us a right to purchase water solutions facilities developed by the other party to the agreements. During the six months ended September 30, 2015, we purchased eight water treatment and disposal facilities under these development agreements. On a combined basis, we paid $82.6 million of cash and issued 386,383 common units, valued at $11.4 million, in exchange for these facilities.

 

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

 

Property, plant and equipment:

 

 

 

Water treatment facilities and equipment (3–30 years)

 

$

32,449

 

Buildings and leasehold improvements (7–30 years)

 

7,281

 

Land

 

1,028

 

Other (5 years)

 

30

 

Goodwill

 

55,529

 

Accrued expenses and other payables

 

(2,102

)

Other noncurrent liabilities

 

(233

)

Fair value of net assets acquired

 

$

93,982

 

 

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Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

Retail Propane Businesses

 

During the six months ended September 30, 2015, we acquired four retail propane businesses and paid $15.9 million of cash on a combined basis in exchange for these assets and operations. The agreements for these acquisitions contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in these business combinations, and as a result, the estimates of fair value at September 30, 2015 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending June 30, 2016.

 

Year Ended March 31, 2015

 

As described in Note 2, pursuant to GAAP, an entity is allowed no more than one year to obtain the information necessary to identify and measure the fair values of the assets acquired and liabilities assumed in a business combination. The changes we made during the six months ended September 30, 2015 to the estimated acquisition date fair values of assets acquired and liabilities assumed in these business combinations are described below. We have not retrospectively adjusted previously issued financial statements for these changes, as we do not believe the changes are material.

 

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

Natural Gas Liquids Storage Facility

 

In February 2015, we acquired Sawtooth NGL Caverns, LLC (“Sawtooth”), which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets and entered into a construction agreement to expand the storage capacity of the facility. We paid $97.6 million of cash, net of cash acquired, and issued 7,396,973 common units, valued at $218.5 million, in exchange for these assets and operations. The agreement for this acquisition contemplates post-closing payments for certain working capital items. We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in this business combination, and as a result, the estimates of fair value at September 30, 2015 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending December 31, 2015. The following table summarizes the preliminary estimates of the fair values of the assets acquired (and useful lives) and liabilities assumed:

 

 

 

Estimated At

 

 

 

 

 

September 30,

 

March 31,

 

 

 

 

 

2015

 

2015

 

Change

 

 

 

(in thousands)

 

Accounts receivable–trade

 

$

42

 

$

42

 

$

 

Prepaid expenses and other current assets

 

843

 

600

 

243

 

Property, plant and equipment:

 

 

 

 

 

 

 

Natural gas liquids terminal and storage assets (2–30 years)

 

62,205

 

62,205

 

 

Vehicles and railcars (3–25 years)

 

75

 

75

 

 

Land

 

68

 

68

 

 

Other

 

32

 

32

 

 

Construction in progress

 

19,525

 

19,525

 

 

Goodwill

 

168,310

 

151,853

 

16,457

 

Intangible assets:

 

 

 

 

 

 

 

Customer relationships (15 years)

 

76,000

 

85,000

 

(9,000

)

Non-compete agreements (10 years)

 

4,300

 

12,000

 

(7,700

)

Accounts payable–trade

 

(931

)

(931

)

 

Accrued expenses and other payables

 

(6,511

)

(6,511

)

 

Advance payments received from customers

 

(1,015

)

(1,015

)

 

Other noncurrent liabilities

 

(6,817

)

(6,817

)

 

Fair value of net assets acquired

 

$

316,126

 

$

316,126

 

$

 

 

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

 

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

 

16



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

The acquisition method of accounting requires that executory contracts with unfavorable terms relative to market conditions at the acquisition date be recorded as assets or liabilities in the acquisition accounting. Since certain storage leases were at unfavorable terms relative to acquisition-date market conditions, we recorded a liability of $12.8 million related to these leases in the acquisition accounting, a portion of which we recorded to accrued expenses and other payables and a portion of which we recorded to other noncurrent liabilities. We amortized $2.9 million of this balance as an increase to revenues during the six months ended September 30, 2015. We will amortize the remainder of this liability over the terms of the leases. The following table summarizes the future amortization of this liability (in thousands):

 

Year Ending March 31,

 

 

 

2016 (six months)

 

$

2,903

 

2017

 

4,905

 

2018

 

1,306

 

2019

 

88

 

 

Bakken Water Solutions Facilities

 

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

 

 

 

 

 

Estimated At

 

 

 

 

 

 

 

March 31,

 

 

 

 

 

Final

 

2015

 

Change

 

 

 

(in thousands)

 

Property, plant and equipment:

 

 

 

 

 

 

 

Vehicles (10 years)

 

$

63

 

$

63

 

$

 

Water treatment facilities and equipment (3—30 years)

 

5,815

 

5,815

 

 

Buildings and leasehold improvements (7—30 years)

 

130

 

130

 

 

Land

 

100

 

100

 

 

Goodwill

 

4,421

 

6,560

 

(2,139

)

Intangible asset:

 

 

 

 

 

 

 

Customer relationships (7 years)

 

24,300

 

22,000

 

2,300

 

Other noncurrent assets

 

75

 

 

75

 

Other noncurrent liabilities

 

(304

)

(68

)

(236

)

Fair value of net assets acquired

 

$

34,600

 

$

34,600

 

$

 

 

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

 

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

 

TransMontaigne Inc.

 

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

 

17



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

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

 

 

 

 

 

Estimated At

 

 

 

 

 

 

 

March 31,

 

 

 

 

 

Final

 

2015

 

Change

 

 

 

(in thousands)

 

Cash and cash equivalents

 

$

1,469

 

$

1,469

 

$

 

Accounts receivable–trade

 

199,366

 

197,829

 

1,537

 

Accounts receivable–affiliates

 

528

 

528

 

 

Inventories

 

373,870

 

373,870

 

 

Prepaid expenses and other current assets

 

15,110

 

15,001

 

109

 

Property, plant and equipment:

 

 

 

 

 

 

 

Refined products terminal assets and equipment (20 years)

 

415,317

 

399,323

 

15,994

 

Vehicles

 

1,696

 

1,698

 

(2

)

Crude oil tanks and related equipment (20 years)

 

1,085

 

1,058

 

27

 

Information technology equipment

 

7,253

 

7,253

 

 

Buildings and leasehold improvements (20 years)

 

15,323

 

14,770

 

553

 

Land

 

61,329

 

70,529

 

(9,200

)

Tank bottoms (indefinite life)

 

46,900

 

46,900

 

 

Other

 

15,536

 

15,534

 

2

 

Construction in progress

 

4,487

 

4,487

 

 

Goodwill

 

30,169

 

28,074

 

2,095

 

Intangible assets:

 

 

 

 

 

 

 

Customer relationships (15 years)

 

66,000

 

76,100

 

(10,100

)

Pipeline capacity rights (30 years)

 

87,618

 

87,618

 

 

Investments in unconsolidated entities

 

240,583

 

240,583

 

 

Other noncurrent assets

 

3,911

 

3,911

 

 

Accounts payable–trade

 

(113,103

)

(113,066

)

(37

)

Accounts payable–affiliates

 

(69

)

(69

)

 

Accrued expenses and other payables

 

(79,405

)

(78,427

)

(978

)

Advance payments received from customers

 

(1,919

)

(1,919

)

 

Long-term debt

 

(234,000

)

(234,000

)

 

Other noncurrent liabilities

 

(33,227

)

(33,227

)

 

Noncontrolling interests

 

(545,120

)

(545,120

)

 

Fair value of net assets acquired

 

$

580,707

 

$

580,707

 

$

 

 

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

 

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

 

18



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

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

 

Water Solutions Facilities

 

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

 

During the six months ended September 30, 2015, we completed the acquisition accounting for 12 of these water treatment and disposal facilities. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these water treatment and disposal facilities:

 

 

 

 

 

Estimated At

 

 

 

 

 

 

 

March 31,

 

 

 

 

 

Final

 

2015

 

Change

 

 

 

(in thousands)

 

Accounts receivable–trade

 

$

939

 

$

939

 

$

 

Inventories

 

253

 

253

 

 

Prepaid expenses and other current assets

 

62

 

62

 

 

Property, plant and equipment:

 

 

 

 

 

 

 

Water treatment facilities and equipment (3–30 years)

 

60,784

 

60,784

 

 

Buildings and leasehold improvements (7–30 years)

 

5,701

 

5,701

 

 

Land

 

2,122

 

2,122

 

 

Other (5 years)

 

101

 

101

 

 

Goodwill

 

93,358

 

93,358

 

 

Intangible asset:

 

 

 

 

 

 

Customer relationships (4 years)

 

10,000

 

10,000

 

 

Other noncurrent assets

 

50

 

50

 

 

Accounts payable–trade

 

(58

)

(58

)

 

Accrued expenses and other payables

 

(1,092

)

(1,092

)

 

Other noncurrent liabilities

 

(420

)

(420

)

 

Noncontrolling interest

 

(5,775

)

(5,775

)

 

Fair value of net assets acquired

 

$

166,025

 

$

166,025

 

$

 

 

19



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

 

 

Estimated At

 

 

 

 

 

September 30,

 

March 31,

 

 

 

 

 

2015

 

2015

 

Change

 

 

 

(in thousands)

 

Property, plant and equipment:

 

 

 

 

 

 

 

Water treatment facilities and equipment (3–30 years)

 

$

19,198

 

$

18,922

 

$

276

 

Buildings and leasehold improvements (7–30 years)

 

4,989

 

4,549

 

440

 

Land

 

1,005

 

987

 

18

 

Other (5 years)

 

31

 

28

 

3

 

Goodwill

 

38,675

 

39,412

 

(737

)

Accrued expenses and other payables

 

(2,000

)

(2,000

)

 

Other noncurrent liabilities

 

(162

)

(162

)

 

Fair value of net assets acquired

 

$

61,736

 

61,736

 

$

 

 

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

 

Retail Propane Businesses

 

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

 

20



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

 

 

 

 

Estimated At

 

 

 

 

 

 

 

March 31,

 

 

 

 

 

Final

 

2015

 

Change

 

 

 

(in thousands)

 

Accounts receivable–trade

 

$

2,237

 

$

2,237

 

$

 

Inventories

 

771

 

771

 

 

Prepaid expenses and other current assets

 

110

 

110

 

 

Property, plant and equipment:

 

 

 

 

 

 

 

Retail propane equipment (15–20 years)

 

13,177

 

13,177

 

 

Vehicles and railcars (5–7 years)

 

2,332

 

2,332

 

 

Buildings and leasehold improvements (30 years)

 

534

 

784

 

(250

)

Land

 

505

 

655

 

(150

)

Other (5–7 years)

 

118

 

116

 

2

 

Goodwill

 

8,097

 

8,097

 

 

Intangible assets:

 

 

 

 

 

 

 

Customer relationships (10–15 years)

 

17,563

 

17,563

 

 

Non-compete agreements (5–7 years)

 

500

 

500

 

 

Trade names (3–12 years)

 

950

 

950

 

 

Accounts payable–trade

 

(1,523

)

(1,921

)

398

 

Advance payments received from customers

 

(1,750

)

(1,750

)

 

Current maturities of long-term debt

 

(78

)

(78

)

 

Long-term debt, net of current maturities

 

(760

)

(760

)

 

Fair value of net assets acquired

 

$

42,783

 

$

42,783

 

$

 

 

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

 

21



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

Note 5—Property, Plant and Equipment

 

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

 

 

 

Estimated

 

September 30,

 

March 31,

 

Description

 

Useful Lives

 

2015

 

2015

 

 

 

 

 

(in thousands)

 

Natural gas liquids terminal and storage assets

 

2–30 years

 

$

134,335

 

$

132,851

 

Refined products terminal assets and equipment

 

20 years

 

439,154

 

403,609

 

Retail propane equipment

 

2–30 years

 

191,493

 

181,140

 

Vehicles and railcars

 

3–25 years

 

185,216

 

180,679

 

Water treatment facilities and equipment

 

3–30 years

 

405,382

 

317,317

 

Crude oil tanks and related equipment

 

2–40 years

 

113,524

 

109,909

 

Barges and towboats

 

5–40 years

 

78,718

 

59,848

 

Information technology equipment

 

3–7 years

 

39,558

 

34,915

 

Buildings and leasehold improvements

 

3–40 years

 

118,338

 

98,989

 

Land

 

 

 

101,245

 

107,098

 

Tank bottoms

 

 

 

64,741

 

62,656

 

Other

 

3–30 years

 

35,818

 

34,415

 

Construction in progress

 

 

 

207,922

 

96,922

 

 

 

 

 

2,115,444

 

1,820,348

 

Accumulated depreciation

 

 

 

(270,332

)

(202,959

)

Net property, plant and equipment

 

 

 

$

1,845,112

 

$

1,617,389

 

 

The following table summarizes depreciation expense for the periods indicated:

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

2015

 

2014

 

2015

 

2014

 

(in thousands)

 

$

34,469

 

$

28,387

 

$

70,264

 

$

46,870

 

 

Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms when the storage tanks are removed from service. The following table summarizes the tank bottoms included in the table above at the dates indicated:

 

 

 

September 30, 2015

 

March 31, 2015

 

 

 

Volume

 

 

 

Volume

 

 

 

Product

 

(in barrels)
(in thousands)

 

Value
(in thousands)

 

(in barrels)
(in thousands)

 

Value
(in thousands)

 

Gasoline

 

219

 

$

25,710

 

219

 

$

25,710

 

Crude oil

 

231

 

19,320

 

184

 

16,835

 

Diesel

 

121

 

14,753

 

124

 

15,153

 

Renewables

 

41

 

4,220

 

41

 

4,220

 

Other

 

12

 

738

 

12

 

738

 

Total

 

 

 

$

64,741

 

 

 

$

62,656

 

 

22



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

Note 6—Goodwill

 

The following table summarizes changes in goodwill by segment for the six months ended September 30, 2015:

 

 

 

 

 

 

 

 

 

 

 

Refined

 

 

 

 

 

Crude Oil

 

Water

 

 

 

Retail

 

Products and

 

 

 

 

 

Logistics

 

Solutions

 

Liquids

 

Propane

 

Renewables

 

Total

 

 

 

(in thousands)

 

Balances at March 31, 2015

 

$

579,846

 

$

401,656

 

$

234,803

 

$

122,382

 

$

64,074

 

$

1,402,761

 

Revisions to acquisition accounting (Note 4)

 

 

(2,876

)

16,457

 

 

2,095

 

15,676

 

Acquisitions (Note 4)

 

 

68,305

 

 

4,186

 

 

72,491

 

Balances at September 30, 2015

 

$

579,846

 

$

467,085

 

$

251,260

 

$

126,568

 

$

66,169

 

$

1,490,928

 

 

Note 7—Intangible Assets

 

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

 

 

 

 

 

September 30, 2015

 

March 31, 2015

 

 

 

Estimated

 

Gross Carrying

 

Accumulated

 

Gross Carrying

 

Accumulated

 

Description

 

Useful Lives

 

Amount

 

Amortization

 

Amount

 

Amortization

 

 

 

 

 

(in thousands)

 

Amortizable–

 

 

 

 

 

 

 

 

 

 

 

Customer relationships

 

3–20 years

 

$

924,467

 

$

199,578

 

$

921,418

 

$

159,215

 

Pipeline capacity rights

 

30 years

 

119,636

 

4,565

 

119,636

 

2,571

 

Water facility development agreement

 

5 years

 

14,000

 

6,300

 

14,000

 

4,900

 

Executory contracts and other agreements

 

2–10 years

 

23,920

 

19,768

 

23,920

 

18,387

 

Non-compete agreements

 

2–10 years

 

19,388

 

12,169

 

26,662

 

10,408

 

Trade names

 

2–12 years

 

15,439

 

10,399

 

15,439

 

7,569

 

Debt issuance costs

 

3–10 years

 

56,545

 

22,044

 

55,165

 

17,467

 

Total amortizable

 

 

 

1,173,395

 

274,823

 

1,176,240

 

220,517

 

Non-amortizable–

 

 

 

 

 

 

 

 

 

 

 

Customer commitments

 

 

 

310,000

 

 

310,000

 

 

Trade names

 

 

 

22,620

 

 

22,620

 

 

Total non-amortizable

 

 

 

332,620

 

 

332,620

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

$

1,506,015

 

$

274,823

 

$

1,508,860

 

$

220,517

 

 

The weighted-average remaining amortization period for intangible assets is approximately 11 years.

 

Amortization expense is as follows for the periods indicated:

 

 

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

Recorded In

 

2015

 

2014

 

2015

 

2014

 

 

 

(in thousands)

 

Depreciation and amortization

 

$

22,291

 

$

21,711

 

$

46,328

 

$

42,604

 

Cost of sales

 

1,700

 

1,984

 

3,401

 

4,121

 

Interest expense

 

2,276

 

2,117

 

4,558

 

4,029

 

Total

 

$

26,267

 

$

25,812

 

$

54,287

 

$

50,754

 

 

23



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

Year Ending March 31,

 

 

 

2016 (six months)

 

$

54,702

 

2017

 

104,446

 

2018

 

100,474

 

2019

 

90,926

 

2020

 

84,159

 

Thereafter

 

463,865

 

Total

 

$

898,572

 

 

Note 8—Long-Term Debt

 

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

 

 

 

September 30,

 

March 31,

 

 

 

2015

 

2015

 

 

 

(in thousands)

 

Revolving credit facility–

 

 

 

 

 

Expansion capital borrowings

 

$

1,083,000

 

$

702,500

 

Working capital borrowings

 

656,000

 

688,000

 

5.125% Notes due 2019

 

400,000

 

400,000

 

6.875% Notes due 2021

 

450,000

 

450,000

 

6.650% Notes due 2022

 

250,000

 

250,000

 

TLP credit facility

 

249,600

 

250,000

 

Other long-term debt

 

9,134

 

9,271

 

 

 

3,097,734

 

2,749,771

 

Less: Current maturities

 

4,040

 

4,472

 

Long-term debt

 

$

3,093,694

 

$

2,745,299

 

 

Credit Agreement

 

We have entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). At September 30, 2015, our Revolving Credit Facility had a total capacity of $2.296 billion.

 

The Expansion Capital Facility had a total capacity of $1.258 billion for cash borrowings at September 30, 2015. At that date, we had outstanding borrowings of $1.083 billion on the Expansion Capital Facility. The Working Capital Facility had a total capacity of $1.038 billion for cash borrowings and letters of credit at September 30, 2015. At that date, we had outstanding borrowings of $656.0 million and outstanding letters of credit of $89.6 million on the Working Capital Facility. Amounts outstanding for letters of credit are not recorded as long-term debt on our condensed consolidated balance sheets, although they decrease our borrowing capacity under the Working Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base,” as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time. During October 2015, we entered into an agreement with the lenders to increase the total capacity on the Expansion Capital Facility by $150 million.

 

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

 

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Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

All borrowings under the Credit Agreement bear interest, at our option, at either (i) an alternate base rate plus a margin of 0.50% to 1.50% per year or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per year. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At September 30, 2015, the borrowings under the Credit Agreement were LIBOR borrowings with an interest rate at September 30, 2015 of 2.21%, calculated as the LIBOR rate of 0.21% plus a margin of 2.0%. At September 30, 2015, the interest rate in effect on letters of credit was 2.25%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused capacity.

 

The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our leverage ratio, as defined in the Credit Agreement, cannot exceed 4.25 to 1 at any quarter end. The leverage coverage ratio in our Credit Agreement excludes TLP’s debt. At September 30, 2015, our leverage ratio was approximately 3.5 to 1. The Credit Agreement also specifies that our interest coverage ratio, as defined in the Credit Agreement, cannot be less than 2.75 to 1 at any quarter end. At September 30, 2015, our interest coverage ratio was approximately 5.9 to 1.

 

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

 

At September 30, 2015, we were in compliance with the covenants under the Credit Agreement.

 

2019 Notes

 

On July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the “2019 Notes”). The 2019 Notes mature on July 15, 2019. Interest is payable on January 15 and July 15 of each year. We have the right to redeem the 2019 Notes before the maturity date, although we would be required to pay a premium for early redemption.

 

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2019 Notes, and the obligations under the 2019 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The indenture governing the 2019 Notes contains various customary covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

 

At September 30, 2015, we were in compliance with the covenants under the indenture governing the 2019 Notes.

 

2021 Notes

 

On October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the “2021 Notes”). The 2021 Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the 2021 Notes before the maturity date, although we would be required to pay a premium for early redemption.

 

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2021 Notes, and the obligations under the 2021 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The indenture governing the 2021 Notes contains various customary covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

 

At September 30, 2015, we were in compliance with the covenants under the indenture governing the 2021 Notes.

 

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Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

2022 Notes

 

On June 19, 2012, we entered into a Note Purchase Agreement (as amended, the “Note Purchase Agreement”) whereby we issued $250.0 million of Senior Notes in a private placement (the “2022 Notes”). The 2022 Notes bear interest at a fixed rate of 6.65%, which is payable quarterly. The 2022 Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to prepay outstanding principal, although we would incur a prepayment penalty. The 2022 Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

 

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

 

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

 

At September 30, 2015, we were in compliance with the covenants under the Note Purchase Agreement.

 

TLP Credit Facility

 

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

 

TLP may elect to have loans under the TLP Credit Facility bear interest at either (i) a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLP also pays commitment fees on any unused capacity, ranging from 0.375% to 0.5% per year, depending on the total leverage ratio then in effect. For the three months ended September 30, 2015, the weighted-average interest rate on borrowings under the TLP Credit Facility was approximately 2.6%. TLP’s obligations under the TLP Credit Facility are secured by a first priority security interest in favor of the lenders in the majority of TLP’s assets, including TLP’s investments in unconsolidated entities. At September 30, 2015, TLP had outstanding borrowings under the TLP Credit Facility of $249.6 million and no outstanding letters of credit.

 

The TLP Credit Facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the TLP Credit Facility are (i) a total leverage ratio test (not to exceed 4.75 times), (ii) a senior secured leverage ratio test (not to exceed 3.75 times) if TLP issues senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times). These financial covenants are based on “Consolidated EBITDA” as defined in the TLP Credit Facility. The TLP Credit Facility is non-recourse to the Partnership. At September 30, 2015, TLP was in compliance with the covenants under the TLP Credit Facility.

 

26



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

The following table summarizes our basis in the assets and liabilities of TLP at September 30, 2015, inclusive of the impact of our acquisition accounting for the business combination with TransMontaigne (in thousands):

 

Cash and cash equivalents

 

$

791

 

Accounts receivable–trade

 

3,074

 

Accounts receivable–affiliates

 

679

 

Inventories

 

1,250

 

Prepaid expenses and other current assets

 

858

 

Property, plant and equipment, net

 

477,357

 

Goodwill

 

30,169

 

Intangible assets, net

 

61,696

 

Investments in unconsolidated entities

 

255,757

 

Other noncurrent assets

 

968

 

Accounts payable–trade

 

(6,760

)

Accounts payable–affiliates

 

(121

)

Net intercompany payable

 

(1,911

)

Accrued expenses and other payables

 

(7,054

)

Advanced payments received from customers

 

(151

)

Long-term debt

 

(249,600

)

Other noncurrent liabilities

 

(3,441

)

Net assets

 

$

563,561

 

 

Other Long-Term Debt

 

We have executed various noninterest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also have certain notes payable related to equipment financing.

 

Debt Maturity Schedule

 

The scheduled maturities of our long-term debt are as follows at September 30, 2015:

 

 

 

Revolving

 

 

 

 

 

 

 

TLP

 

Other

 

 

 

 

 

Credit

 

2019

 

2021

 

2022

 

Credit

 

Long-Term

 

 

 

Year Ending March 31,

 

Facility

 

Notes

 

Notes

 

Notes

 

Facility

 

Debt

 

Total

 

 

 

(in thousands)

 

2016 (six months)

 

$

 

$

 

$

 

$

 

$

 

$

1,891

 

$

1,891

 

2017

 

 

 

 

 

 

2,879

 

2,879

 

2018

 

 

 

 

25,000

 

 

2,129

 

27,129

 

2019

 

1,739,000

 

 

 

50,000

 

249,600

 

1,413

 

2,040,013

 

2020

 

 

400,000

 

 

50,000

 

 

344

 

450,344

 

Thereafter

 

 

 

450,000

 

125,000

 

 

478

 

575,478

 

Total

 

$

1,739,000

 

$

400,000

 

$

450,000

 

$

250,000

 

$

249,600

 

$

9,134

 

$

3,097,734

 

 

Note 9—Income Taxes

 

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

 

27



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

We have certain taxable corporate subsidiaries in the United States and in Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales. Our fiscal years 2012 to 2015 generally remain subject to examination by federal, state, and Canadian tax authorities.

 

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

 

We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in our condensed consolidated financial statements at September 30, 2015 or March 31, 2015.

 

Note 10—Commitments and Contingencies

 

Legal Contingencies

 

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

 

Environmental Matters

 

Our 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.

 

Asset Retirement Obligations

 

Our condensed consolidated balance sheet at September 30, 2015 includes a liability of $4.8 million related to asset retirement obligations, which is reported within other noncurrent liabilities. This liability is related to contractual and regulatory obligations at certain facilities for which we have to perform remediation, dismantlement, or removal activities when the assets are retired.

 

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

 

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.

 

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Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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, 2015 (in thousands):

 

Year Ending March 31,

 

 

 

2016 (six months)

 

$

60,441

 

2017

 

106,125

 

2018

 

90,783

 

2019

 

66,385

 

2020

 

56,509

 

Thereafter

 

123,193

 

Total

 

$

503,436

 

 

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

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

2015

 

2014

 

2015

 

2014

 

(in thousands)

 

$

33,354

 

$

29,333

 

$

67,075

 

$

54,633

 

 

Pipeline Capacity Agreements

 

We have executed noncancelable agreements with crude oil and refined products pipeline operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity. The following table summarizes future minimum throughput payments under these agreements at September 30, 2015 (in thousands):

 

Year Ending March 31,

 

 

 

2016 (six months)

 

$

56,753

 

2017

 

85,349

 

2018

 

85,435

 

2019

 

84,643

 

2020

 

74,811

 

Thereafter

 

90,972

 

Total

 

$

477,963

 

 

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Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

Sales and Purchase Contracts

 

We have entered into product sales and purchase contracts for which we expect the parties to physically settle and deliver the inventory in future periods. The following table summarizes such commitments at September 30, 2015:

 

 

 

Volume

 

Value

 

 

 

(in thousands)

 

Purchase commitments:

 

 

 

 

 

Natural gas liquids fixed-price (gallons)

 

61,618

 

$

38,073

 

Natural gas liquids index-price (gallons)

 

526,956

 

264,790

 

Crude oil fixed-price (barrels)

 

13

 

578

 

Crude oil index-price (barrels)

 

7,982

 

336,151

 

Sale commitments:

 

 

 

 

 

Natural gas liquids fixed-price (gallons)

 

179,849

 

127,038

 

Natural gas liquids index-price (gallons)

 

253,827

 

194,588

 

Crude oil fixed-price (barrels)

 

1,018

 

46,279

 

Crude oil index-price (barrels)

 

7,842

 

391,920

 

 

We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs. Contracts in the table above may have offsetting derivative contracts (see Note 12) or inventory positions (see Note 2).

 

Certain other forward purchase and sale contracts do not qualify for the normal purchase and normal sale election. These contracts are recorded at fair value in our condensed consolidated balance sheet and are not included in the table above. These contracts are included in the derivative disclosures in Note 12, and represent $21.6 million of our prepaid expenses and other current assets and $13.5 million of our accrued expenses and other payables at September 30, 2015.

 

Note 11—Equity

 

Partnership Equity

 

The Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest, which consists of common units. Our general partner is not required to make any additional capital contributions or to guarantee or pay any of our debts and obligations.

 

Common Units Issued in Business Combinations

 

During the six months ended September 30, 2015, we issued 386,383 common units as consideration for a water solutions facility acquisition. In October 2015, we issued 52,199 common units as partial consideration of the acquisition of a retail propane business.

 

Unit Repurchase Program

 

On September 10, 2015, the Board of Directors of our general partner authorized a unit repurchase program, under which we may repurchase up to $45 million of our outstanding common units through March 31, 2016. We may repurchase units from time to time in the open market or in other privately negotiated transactions. The unit repurchase program authorization does not obligate us to repurchase any dollar amount or number of our units. During September 2015, we repurchased 157,626 common units for an aggregate price of $3.7 million.

 

Our Distribution Policy

 

Our general partner has adopted a cash distribution policy that requires us to pay a quarterly distribution to unitholders as of the record date to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and

 

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Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

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

 

 

 

 

 

 

 

 

 

 

 

Marginal Percentage Interest In

 

 

 

 

 

 

 

 

 

 

 

Distributions

 

 

 

Total Quarterly Distribution Per Unit

 

Limited Partners

 

General Partner

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Minimum quarterly distribution

 

 

 

 

 

 

 

$

0.337500

 

99.9

%

0.1

%

First target distribution

 

above

 

$

0.337500

 

up to

 

$

0.388125

 

99.9

%

0.1

%

Second target distribution

 

above

 

$

0.388125

 

up to

 

$

0.421875

 

86.9

%

13.1

%

Third target distribution

 

above

 

$

0.421875

 

up to

 

$

0.506250

 

76.9

%

23.1

%

Thereafter

 

above

 

$

0.506250

 

 

 

 

 

51.9

%

48.1

%

 

In October 2015, we declared a distribution of $0.64 per common unit, to be paid on November 13, 2015 to unitholders of record on November 3, 2015. This distribution is expected to be $83.6 million, including amounts to be paid on common and general partner notional units as well as an incentive distribution.

 

TLP’s Distribution Policy

 

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

 

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Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

 

 

 

 

 

 

 

 

 

 

Marginal Percentage Interest In

 

 

 

 

 

 

 

 

 

 

 

Distributions

 

 

 

Total Quarterly Distribution Per Unit

 

Limited Partners

 

General Partner

 

Minimum quarterly distribution

 

 

 

 

 

 

 

$

0.40

 

98

%

2

%

First target distribution

 

above

 

$

0.40

 

up to

 

$

0.44

 

98

%

2

%

Second target distribution

 

above

 

$

0.44

 

up to

 

$

0.50

 

85

%

15

%

Third target distribution

 

above

 

$

0.50

 

up to

 

$

0.60

 

75

%

25

%

Thereafter

 

above

 

$

0.60

 

 

 

 

 

50

%

50

%

 

In October 2015, TLP declared a distribution of $0.6650 per unit, which was paid on November 6, 2015. We received a total of $4.0 million from this distribution on our general partner interest, IDRs, and limited partner interest. The noncontrolling interest owners received a total of $8.6 million from this distribution.

 

Equity-Based Incentive Compensation

 

Our general partner has adopted a long-term incentive plan (“LTIP”), which allows for the issuance of equity-based incentive 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 in the event of a change in control, at the discretion of the board of directors. No distributions accrue to or are paid on the restricted units during the vesting period. The restricted units include awards that vest contingent on the continued service of the recipients through the vesting date (the “Service Awards”). The restricted units also include awards that are contingent both on the continued service of the recipients through the vesting date and also on the performance of our common units relative to other entities in the Alerian MLP Index (the “Index”) over specified periods of time (the “Performance Awards”).

 

The following table summarizes the Service Award activity during the six months ended September 30, 2015:

 

Unvested Service Award units at March 31, 2015

 

2,260,400

 

Units granted

 

787,562

 

Units vested and issued

 

(820,017

)

Units withheld for employee taxes

 

(443,663

)

Units forfeited

 

(64,000

)

Unvested Service Award units at September 30, 2015

 

1,720,282

 

 

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Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

Year Ending March 31,

 

Number of Units

 

2016 (six months)

 

45,000

 

2017

 

820,641

 

2018

 

747,641

 

Thereafter

 

107,000

 

Unvested Service Award units at September 30, 2015

 

1,720,282

 

 

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

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

2015

 

2014

 

2015

 

2014

 

(in thousands)

 

$

14,859

 

$

13,745

 

$

33,362

 

$

21,659

 

 

Of the restricted units granted and vested during the six months ended September 30, 2015, 465,239 units were granted as a bonus for performance during the fiscal year ended March 31, 2015. We accrued expense of $10.0 million during the fiscal year ended March 31, 2015 and $3.8 million during the three months ended June 30, 2015 for estimates of the value of such bonus units that would be granted. During the three months ended September 30, 2015, we reversed $2.0 million of this expense to true-up the estimate to the $11.8 million of actual expense associated with these bonuses. Since the units were not formally granted until July 2015, the full $11.8 million value is reflected in the expense during the three months ended September 30, 2015 in the table above.

 

The following table summarizes the estimated future expense we expect to record on the unvested Service Award units at September 30, 2015 (in thousands), after taking into consideration estimated forfeitures of approximately 167,000 units. For purposes of this calculation, we used the closing price of our common units on September 30, 2015, which was $19.97.

 

Year Ending March 31,

 

 

 

2016 (six months)

 

$

8,364

 

2017

 

13,533

 

2018

 

4,461

 

Thereafter

 

1,063

 

Total

 

$

27,421

 

 

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Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

Balance at March 31, 2015

 

$

6,154

 

Expense recorded

 

33,362

 

Value of units vested and issued

 

(23,261

)

Taxes paid on behalf of participants

 

(12,663

)

Balance at September 30, 2015

 

$

3,592

 

 

The weighted-average fair value of the Service Award units at September 30, 2015 was $16.35 per common unit, which was calculated as the closing price of our common units on September 30, 2015, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth.

 

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

 

 

 

Maximum Performance

 

Vesting Date of Tranche

 

Award Units

 

July 1, 2016

 

685,382

 

July 1, 2017

 

677,382

 

Total

 

1,362,764

 

 

The number of Performance Award units that will vest is contingent on the performance of our common units relative to the performance of the other entities in the Index. Performance will be calculated based on the return on our common units (including changes in the market price of the common units and distributions paid during the performance period) relative to the returns on the common units of the other entities in the Index. Performance will be measured over the following periods:

 

Vesting Date of Tranche

 

Performance Period for Tranche

 

July 1, 2016

 

July 1, 2013 through June 30, 2016

 

July 1, 2017

 

July 1, 2014 through June 30, 2017

 

 

The following table summarizes the percentage of the maximum Performance Award units that will vest depending on the percentage of entities in the Index that NGL outperforms:

 

Percentage of Entities in the

 

Percentage of Maximum

 

Index that NGL Outperforms

 

Performance Award Units to Vest

 

Less than 50%

 

0%

 

 

50%–75%

 

25%–50%

 

 

75%–90%

 

50%–100%

 

 

Greater than 90%

 

100%

 

 

 

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

 

34



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

The following table summarizes the estimated fair value for each unvested tranche at September 30, 2015 (without consideration of estimated forfeitures):

 

 

 

Fair Value of

 

Vesting Date of Tranche

 

Unvested Awards

 

 

 

(in thousands)

 

July 1, 2016

 

$

4,276

 

July 1, 2017

 

2,906

 

Total

 

$

7,182

 

 

We record the expense for each of the tranches of the Performance Awards on a straight-line basis over the period beginning with the grant date and ending with the vesting date of the tranche. At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using a Monte Carlo simulation. The following table summarizes the expense recorded for each vesting tranche during the periods indicated:

 

 

 

Three Months Ended

 

 

 

Vesting Date of Tranche

 

June 30, 2015

 

September 30, 2015

 

Total

 

 

 

(in thousands)

 

July 1, 2015

 

$

15,469

 

$

609

 

$

16,078

 

July 1, 2016

 

1,720

 

(220

)

1,500

 

July 1, 2017

 

602

 

(60

)

542

 

Total

 

$

17,791

 

$

329

 

$

18,120

 

 

The following table summarizes the estimated future expense we expect to record on the unvested Performance Award units at September 30, 2015 (in thousands), after taking into consideration estimated forfeitures. For purposes of this calculation, we used the September 30, 2015 fair value of the Performance Awards.

 

Year Ending March 31,

 

 

 

2016 (six months)

 

$

2,321

 

2017

 

2,080

 

2018

 

307

 

Total

 

$

4,708

 

 

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

 

Balance at March 31, 2015

 

$

 

Expense recorded

 

18,120

 

Value of units vested and issued

 

(9,658

)

Taxes paid on behalf of participants

 

(6,420

)

Balance at September 30, 2015

 

$

2,042

 

 

The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common units. The maximum number of units deliverable under the LTIP plan automatically increases to 10% of the issued and outstanding common units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount. Units withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, when an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available for new awards under the LTIP. At September 30, 2015, approximately 5.3 million common units remain available for issuance under the LTIP.

 

35



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

Note 12—Fair Value of Financial Instruments

 

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

 

Commodity Derivatives

 

The following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported in our condensed consolidated balance sheet at the dates indicated:

 

 

 

September 30, 2015

 

March 31, 2015

 

 

 

Derivative

 

Derivative

 

Derivative

 

Derivative

 

 

 

Assets

 

Liabilities

 

Assets

 

Liabilities

 

 

 

(in thousands)

 

Level 1 measurements

 

$

41,612

 

$

(5,314

)

$

83,779

 

$

(3,969

)

Level 2 measurements

 

27,464

 

(15,070

)

34,963

 

(28,764

)

 

 

69,076

 

(20,384

)

118,742

 

(32,733

)

 

 

 

 

 

 

 

 

 

 

Netting of counterparty contracts (1)

 

(3,537

)

3,537

 

(1,804

)

1,804

 

Net cash collateral provided (held)

 

(17,980

)

3,118

 

(56,660

)

2,979

 

Commodity derivatives in condensed consolidated balance sheet

 

$

47,559

 

$

(13,729

)

$

60,278

 

$

(27,950

)

 


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

 

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

 

 

 

September 30,

 

March 31,

 

 

 

2015

 

2015

 

 

 

(in thousands)

 

Prepaid expenses and other current assets

 

$

47,559

 

$

60,278

 

Accrued expenses and other payables

 

(13,729

)

(27,950

)

Net commodity derivative asset

 

$

33,830

 

$

32,328

 

 

36



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

 

 

 

 

Net Long (Short)

 

Fair Value

 

 

 

 

 

Notional

 

of

 

 

 

 

 

Units

 

Net Assets

 

Contracts

 

Settlement Period

 

(Barrels)

 

(Liabilities)

 

 

 

 

 

(in thousands)

 

At September 30, 2015–

 

 

 

 

 

 

 

Cross-commodity (1)

 

October 2015–March 2017

 

86

 

$

886

 

Crude oil fixed-price (2)

 

October 2015–December 2016

 

(1,540

)

3,407

 

Propane fixed-price (2)

 

October 2015–December 2017

 

1,005

 

(3,925

)

Refined products fixed-price (2)

 

October 2015–January 2017

 

(3,580

)

43,331

 

Other

 

October 2015–June 2016

 

 

 

4,993

 

 

 

 

 

 

 

48,692

 

Net cash collateral held

 

 

 

 

 

(14,862

)

Net commodity derivatives in condensed consolidated balance sheet

 

 

 

 

 

$

33,830

 

 

 

 

 

 

 

 

 

At March 31, 2015–

 

 

 

 

 

 

 

Cross-commodity (1)

 

April 2015–March 2016

 

98

 

$

(105

)

Crude oil fixed-price (2)

 

April 2015–June 2015

 

(1,113

)

(171

)

Crude oil index-price (3)

 

April 2015–July 2015

 

751

 

1,835

 

Propane fixed-price (2)

 

April 2015–December 2016

 

193

 

(2,842

)

Refined products fixed-price (2)

 

April 2015–December 2015

 

(3,005

)

84,996

 

Other

 

April 2015–December 2015

 

 

 

2,296

 

 

 

 

 

 

 

86,009

 

Net cash collateral held

 

 

 

 

 

(53,681

)

Net commodity derivatives in condensed consolidated balance sheet

 

 

 

 

 

$

32,328

 

 


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

 

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

 

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

 

37



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

2015

 

2014

 

2015

 

2014

 

(in thousands)

 

$

85,777

 

$

55,981

 

$

44,534

 

$

38,496

 

 

Credit Risk

 

We have credit policies with regard to our counterparties on derivative financial instruments 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, 2015, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, as the counterparties may be similarly affected by changes in economic, regulatory or other conditions. If a counterparty does not perform on a contract, we may not realize amounts that have been recorded in our condensed consolidated balance sheets and recognized in our net income.

 

Interest Rate Risk

 

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, 2015, we had $1.739 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 2.21%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $2.2 million, based on borrowings outstanding at September 30, 2015.

 

The TLP Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At September 30, 2015, TLP had $249.6 million of outstanding borrowings under the TLP Credit Facility at a rate of 2.72%. A change in interest rates of 0.125% would result in an increase or decrease in TLP’s annual interest expense of $0.3 million, based on borrowings outstanding at September 30, 2015.

 

Fair Value of Fixed-Rate Notes

 

The following table provides fair value estimates of our fixed-rate notes at September 30, 2015 (in thousands):

 

5.125% Notes due 2019

 

$

378,000

 

6.875% Notes due 2021

 

446,625

 

6.650% Notes due 2022

 

254,175

 

 

For the 2019 Notes and the 2021 Notes, the fair value estimates were developed based on publicly traded quotes and would be classified as Level 1 in the fair value hierarchy. For the 2022 Notes, the fair value estimate was developed using observed yields on publicly traded notes issued by other entities, adjusted for differences in the key terms of those notes and the key terms of our notes (examples include differences in the tenor of the debt, credit standing of the issuer, whether the notes are publicly traded, and whether the notes are secured or unsecured). This fair value estimate would be classified as Level 3 in the fair value hierarchy.

 

Note 13—Segments

 

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

 

38



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

 

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

(in thousands)

 

Revenues(1):

 

 

 

 

 

 

 

 

 

Crude oil logistics–

 

 

 

 

 

 

 

 

 

Crude oil sales

 

$

997,106

 

$

2,109,618

 

$

2,309,889

 

$

4,038,673

 

Crude oil transportation and other

 

12,746

 

11,581

 

31,695

 

21,584

 

Water solutions–

 

 

 

 

 

 

 

 

 

Service fees

 

35,203

 

24,238

 

71,941

 

41,939

 

Recovered hydrocarbons

 

10,746

 

23,334

 

26,564

 

47,349

 

Water transportation

 

 

5,147

 

 

10,745

 

Other revenues

 

1,545

 

 

3,282

 

 

Liquids–

 

 

 

 

 

 

 

 

 

Propane sales

 

98,770

 

240,933

 

204,260

 

463,736

 

Other product sales

 

160,836

 

306,660

 

308,347

 

595,075

 

Other revenues

 

10,122

 

6,279

 

19,622

 

11,582

 

Retail propane–

 

 

 

 

 

 

 

 

 

Propane sales

 

36,119

 

48,552

 

79,304

 

100,578

 

Distillate sales

 

7,678

 

11,530

 

20,625

 

30,225

 

Other revenues

 

9,409

 

8,276

 

17,724

 

15,457

 

Refined products and renewables–

 

 

 

 

 

 

 

 

 

Refined products sales

 

1,704,259

 

2,466,389

 

3,413,208

 

3,452,612

 

Renewables sales

 

93,189

 

116,825

 

199,342

 

248,099

 

Service fees

 

28,739

 

24,006

 

56,812

 

24,006

 

Corporate and other

 

 

1,333

 

 

2,794

 

Elimination of intersegment sales

 

(13,272

)

(24,175

)

(30,951

)

(75,314

)

Total revenues

 

$

3,193,195

 

$

5,380,526

 

$

6,731,664

 

$

9,029,140

 

 

 

 

 

 

 

 

 

 

 

Depreciation and Amortization:

 

 

 

 

 

 

 

 

 

Crude oil logistics

 

$

10,053

 

$

9,240

 

$

20,055

 

$

18,971

 

Water solutions

 

22,416

 

17,573

 

43,262

 

34,665

 

Liquids

 

2,745

 

3,384

 

7,749

 

6,585

 

Retail propane

 

8,909

 

7,684

 

17,615

 

15,255

 

Refined products and renewables

 

11,152

 

11,917

 

25,327

 

12,761

 

Corporate and other

 

1,486

 

301

 

2,584

 

1,237

 

Total depreciation and amortization

 

$

56,761

 

$

50,099

 

$

116,592

 

$

89,474

 

 

 

 

 

 

 

 

 

 

 

Operating Income (Loss):

 

 

 

 

 

 

 

 

 

Crude oil logistics

 

$

(75

)

$

38

 

$

11,885

 

$

1,501

 

Water solutions

 

205

 

14,792

 

(2,867

)

13,885

 

Liquids

 

20,370

 

10,929

 

19,899

 

10,016

 

Retail propane

 

(1,765

)

(3,062

)

(2,465

)

(4,648

)

Refined products and renewables

 

(5,244

)

8,822

 

27,776

 

7,567

 

Corporate and other

 

(13,245

)

(23,749

)

(68,711

)

(41,106

)

Total operating income (loss)

 

$

246

 

$

7,770

 

$

(14,483

)

$

(12,785

)

 


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

 

39



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

 

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

(in thousands)

 

Additions to property, plant and equipment:

 

 

 

 

 

 

 

 

 

Crude oil logistics

 

$

44,384

 

$

39,464

 

$

107,023

 

$

81,413

 

Water solutions

 

56,531

 

40,610

 

117,020

 

48,072

 

Liquids

 

18,886

 

1,911

 

36,064

 

3,070

 

Retail propane

 

12,748

 

9,567

 

19,643

 

12,411

 

Refined products and renewables

 

7,588

 

512,281

 

23,283

 

512,281

 

Corporate and other

 

 

1,809

 

1,169

 

3,262

 

Total

 

$

140,137

 

$

605,642

 

$

304,202

 

$

660,509

 

 

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

 

 

 

September 30,

 

March 31,

 

 

 

2015

 

2015

 

 

 

(in thousands)

 

Long-lived assets, net:

 

 

 

 

 

Crude oil logistics

 

$

1,412,181

 

$

1,327,538

 

Water solutions

 

1,275,920

 

1,119,794

 

Liquids

 

559,763

 

534,560

 

Retail propane

 

477,391

 

467,652

 

Refined products and renewables

 

795,167

 

808,757

 

Corporate and other

 

46,810

 

50,192

 

Total

 

$

4,567,232

 

$

4,308,493

 

 

 

 

 

 

 

Total assets:

 

 

 

 

 

Crude oil logistics

 

$

2,088,087

 

$

2,337,188

 

Water solutions

 

1,375,023

 

1,185,929

 

Liquids

 

770,052

 

713,547

 

Retail propane

 

541,002

 

542,476

 

Refined products and renewables

 

1,549,577

 

1,668,836

 

Corporate and other

 

126,096

 

99,525

 

Total

 

$

6,449,837

 

$

6,547,501

 

 

Note 14—Transactions with Affiliates

 

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

 

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

 

Certain members of our management and members of their families own interests in entities from which we have purchased products and services and to which we have sold products and services. During the six months ended September 30, 2015, $23.2 million of these transactions were capital expenditures and were recorded as increases to property, plant and equipment.

 

40



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

The following table summarizes these related party transactions:

 

 

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

(in thousands)

 

Sales to SemGroup

 

$

4,593

 

$

37,600

 

$

42,031

 

$

63,583

 

Purchases from SemGroup

 

6,478

 

46,564

 

45,303

 

85,684

 

Sales to equity method investees

 

1,696

 

9,131

 

3,086

 

9,131

 

Purchases from equity method investees

 

24,816

 

34,689

 

55,764

 

70,965

 

Sales to entities affiliated with management

 

91

 

1,706

 

198

 

1,854

 

Purchases from entities affiliated with management

 

16,214

 

3,845

 

23,394

 

6,984

 

 

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

 

 

 

September 30,

 

March 31,

 

 

 

2015

 

2015

 

 

 

(in thousands)

 

Receivables from SemGroup

 

$

5,456

 

$

13,443

 

Receivables from equity method investees

 

679

 

652

 

Receivables from entities affiliated with management

 

210

 

3,103

 

Total

 

$

6,345

 

$

17,198

 

 

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

 

 

 

September 30,

 

March 31,

 

 

 

2015

 

2015

 

 

 

(in thousands)

 

Payables to SemGroup

 

$

5,912

 

$

11,546

 

Payables to equity method investees

 

4,741

 

6,788

 

Payables to entities affiliated with management

 

8,141

 

7,460

 

Total

 

$

18,794

 

$

25,794

 

 

We also have a loan receivable of $23.8 million at September 30, 2015 from one of our equity method investees. The investee is required to make monthly principal payments beginning on June 1, 2018 with the remaining principal balance due on May 31, 2020.

 

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

 

Certain of our wholly owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the 2019 Notes and 2021 Notes (see Note 8). Pursuant to Rule 3—10 of Regulation S-X, we have presented in columnar format the condensed consolidating financial information for NGL Energy Partners LP, NGL Energy Finance Corp. (which, along with NGL Energy Partners LP, is a co-issuer of the 2019 Notes and 2021 Notes), the guarantor subsidiaries on a combined basis, and the non-guarantor subsidiaries on a combined basis in the tables below.

 

41



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

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

 

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

 

42



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)

 

 

 

September 30, 2015

 

 

 

NGL Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners LP

 

NGL Energy

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

(Parent) (1)

 

Finance Corp. (1)

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Consolidated

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

23,042

 

$

 

$

4,547

 

$

2,464

 

$

 

$

30,053

 

Accounts receivable—trade, net of allowance for doubtful accounts

 

 

 

702,282

 

9,743

 

 

712,025

 

Accounts receivable—affiliates

 

 

 

5,666

 

679

 

 

6,345

 

Inventories

 

 

 

406,633

 

1,741

 

 

408,374

 

Prepaid expenses and other current assets

 

 

 

103,017

 

17,105

 

 

120,122

 

Total current assets

 

23,042

 

 

1,222,145

 

31,732

 

 

1,276,919

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation

 

 

 

1,300,194

 

544,918

 

 

1,845,112

 

GOODWILL

 

 

 

1,458,567

 

32,361

 

 

1,490,928

 

INTANGIBLE ASSETS, net of accumulated amortization

 

16,090

 

 

1,150,618

 

64,484

 

 

1,231,192

 

INVESTMENTS IN UNCONSOLIDATED ENTITIES

 

 

 

217,482

 

255,757

 

 

473,239

 

NET INTERCOMPANY RECEIVABLES (PAYABLES)

 

1,465,775

 

 

(1,428,990

)

(36,785

)

 

 

INVESTMENTS IN CONSOLIDATED SUBSIDIARIES

 

1,556,474

 

 

77,741

 

 

(1,634,215

)

 

LOAN RECEIVABLE—AFFILIATE

 

 

 

23,775

 

 

 

23,775

 

OTHER NONCURRENT ASSETS

 

 

 

107,215

 

1,457

 

 

108,672

 

Total assets

 

$

3,061,381

 

$

 

$

4,128,747

 

$

893,924

 

$

(1,634,215

)

$

6,449,837

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts payable—trade

 

$

 

$

 

$

559,744

 

$

8,779

 

$

 

$

568,523

 

Accounts payable—affiliates

 

1

 

 

18,672

 

121

 

 

18,794

 

Accrued expenses and other payables

 

19,233

 

 

137,095

 

8,105

 

 

164,433

 

Advance payments received from customers

 

 

 

95,573

 

807

 

 

96,380

 

Current maturities of long-term debt

 

 

 

3,859

 

181

 

 

4,040

 

Total current liabilities

 

19,234

 

 

814,943

 

17,993

 

 

852,170

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LONG-TERM DEBT, net of current maturities

 

1,100,000

 

 

1,743,548

 

250,146

 

 

3,093,694

 

OTHER NONCURRENT LIABILITIES

 

 

 

13,782

 

3,897

 

 

17,679

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EQUITY:

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners’ equity

 

1,942,147

 

 

1,556,474

 

622,024

 

(2,178,362

)

1,942,283

 

Accumulated other comprehensive loss

 

 

 

 

(136

)

 

(136

)

Noncontrolling interests

 

 

 

 

 

544,147

 

544,147

 

Total equity

 

1,942,147

 

 

1,556,474

 

621,888

 

(1,634,215

)

2,486,294

 

Total liabilities and equity

 

$

3,061,381

 

$

 

$

4,128,747

 

$

893,924

 

$

(1,634,215

)

$

6,449,837

 

 


(1)

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

 

43



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Balance Sheet

(U.S. Dollars in Thousands)

 

 

 

March 31, 2015

 

 

 

NGL Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners LP

 

NGL Energy

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

(Parent) (1)

 

Finance Corp. (1)

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Consolidated

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

29,115

 

$

 

$

9,757

 

$

2,431

 

$

 

$

41,303

 

Accounts receivable—trade, net of allowance for doubtful accounts

 

 

 

1,007,001

 

17,225

 

 

1,024,226

 

Accounts receivable—affiliates

 

5

 

 

16,610

 

583

 

 

17,198

 

Inventories

 

 

 

440,026

 

1,736

 

 

441,762

 

Prepaid expenses and other current assets

 

 

 

104,528

 

16,327

 

 

120,855

 

Total current assets

 

29,120

 

 

1,577,922

 

38,302

 

 

1,645,344

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation

 

 

 

1,093,018

 

524,371

 

 

1,617,389

 

GOODWILL

 

 

 

1,372,690

 

30,071

 

 

1,402,761

 

INTANGIBLE ASSETS, net of accumulated amortization

 

17,834

 

 

1,195,896

 

74,613

 

 

1,288,343

 

INVESTMENTS IN UNCONSOLIDATED ENTITIES

 

 

 

217,600

 

255,073

 

 

472,673

 

NET INTERCOMPANY RECEIVABLES (PAYABLES)

 

1,363,792

 

 

(1,319,724

)

(44,068

)

 

 

INVESTMENTS IN CONSOLIDATED SUBSIDIARIES

 

1,834,738

 

 

56,690

 

 

(1,891,428

)

 

LOAN RECEIVABLE—AFFILIATE

 

 

 

8,154

 

 

 

8,154

 

OTHER NONCURRENT ASSETS

 

 

 

110,120

 

2,717

 

 

112,837

 

Total assets

 

$

3,245,484

 

$

 

$

4,312,366

 

$

881,079

 

$

(1,891,428

)

$

6,547,501

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts payable—trade

 

$

 

$

 

$

820,441

 

$

12,939

 

$

 

$

833,380

 

Accounts payable—affiliates

 

 

 

25,690

 

104

 

 

25,794

 

Accrued expenses and other payables

 

19,690

 

 

165,819

 

9,607

 

 

195,116

 

Advance payments received from customers

 

 

 

53,903

 

331

 

 

54,234

 

Current maturities of long-term debt

 

 

 

4,413

 

59

 

 

4,472

 

Total current liabilities

 

19,690

 

 

1,070,266

 

23,040

 

 

1,112,996

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LONG-TERM DEBT, net of current maturities

 

1,100,000

 

 

1,395,100

 

250,199

 

 

2,745,299

 

OTHER NONCURRENT LIABILITIES

 

 

 

12,262

 

3,824

 

 

16,086

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EQUITY:

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners’ equity

 

2,125,794

 

 

1,834,738

 

604,125

 

(2,438,754

)

2,125,903

 

Accumulated other comprehensive loss

 

 

 

 

(109

)

 

(109

)

Noncontrolling interests

 

 

 

 

 

547,326

 

547,326

 

Total equity

 

2,125,794

 

 

1,834,738

 

604,016

 

(1,891,428

)

2,673,120

 

Total liabilities and equity

 

$

3,245,484

 

$

 

$

4,312,366

 

$

881,079

 

$

(1,891,428

)

$

6,547,501

 

 


(1)

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

 

44



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

 

 

 

Three Months Ended September 30, 2015

 

 

 

NGL Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners LP

 

NGL Energy

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

(Parent) (1)

 

Finance Corp. (1)

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

REVENUES

 

$

 

$

 

$

3,153,370

 

$

49,442

 

$

(9,617

)

$

3,193,195

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

COST OF SALES

 

 

 

3,009,777

 

5,610

 

(9,561

)

3,005,826

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATING COSTS AND EXPENSES:

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating

 

 

 

77,166

 

22,663

 

(56

)

99,773

 

General and administrative

 

 

 

24,538

 

4,760

 

 

29,298

 

Depreciation and amortization

 

 

 

45,006

 

11,755

 

 

56,761

 

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

 

 

 

1,294

 

(3

)

 

1,291

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Income (Loss)

 

 

 

(4,411

)

4,657

 

 

246

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity in earnings (losses) of unconsolidated entities

 

 

 

(23

)

2,455

 

 

2,432

 

Interest expense

 

(17,913

)

 

(11,351

)

(2,381

)

74

 

(31,571

)

Other income, net

 

 

 

1,916

 

113

 

(74

)

1,955

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (Loss) Before Income Taxes

 

(17,913

)

 

(13,869

)

4,844

 

 

(26,938

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

INCOME TAX (PROVISION) BENEFIT

 

 

 

2,793

 

(7

)

 

2,786

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES

 

(9,130

)

 

1,946

 

 

7,184

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss)

 

(27,043

)

 

(9,130

)

4,837

 

7,184

 

(24,152

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER

 

 

 

 

 

 

 

 

 

(16,166

)

(16,166

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

 

 

 

 

 

 

 

 

 

(2,891

)

(2,891

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS

 

$

(27,043

)

$

 

$

(9,130

)

$

4,837

 

$

(11,873

)

$

(43,209

)

 


(1)

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

 

45



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

 

 

 

Three Months Ended September 30, 2014

 

 

 

NGL Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners LP

 

NGL Energy

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

(Parent) (1)

 

Finance Corp. (1)

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

REVENUES

 

$

 

$

 

$

5,325,186

 

$

55,364

 

$

(24

)

$

5,380,526

 

 

 

 

 

 

 

 

 

 

 

.

 

 

 

COST OF SALES

 

 

 

5,161,935

 

17,554

 

(24

)

5,179,465

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATING COSTS AND EXPENSES:

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating

 

 

 

80,084

 

17,335

 

 

97,419

 

General and administrative

 

 

 

36,360

 

5,279

 

 

41,639

 

Depreciation and amortization

 

 

 

38,999

 

11,100

 

 

50,099

 

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

 

 

 

4,216

 

(82

)

 

4,134

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Income

 

 

 

3,592

 

4,178

 

 

7,770

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity in earnings of unconsolidated entities

 

 

 

2,310

 

1,387

 

 

3,697

 

Interest expense

 

(17,201

)

 

(9,956

)

(1,506

)

12

 

(28,651

)

Other expense, net

 

 

 

(524

)

(81

)

(12

)

(617

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (Loss) Before Income Taxes

 

(17,201

)

 

(4,578

)

3,978

 

 

(17,801

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

INCOME TAX (PROVISION) BENEFIT

 

 

 

1,951

 

(29

)

 

1,922

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES

 

(2,023

)

 

604

 

 

1,419

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss)

 

(19,224

)

 

(2,023

)

3,949

 

1,419

 

(15,879

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER

 

 

 

 

 

 

 

 

 

(11,056

)

(11,056

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

 

 

 

 

 

 

 

 

 

(3,345

)

(3,345

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS

 

$

(19,224

)

$

 

$

(2,023

)

$

3,949

 

$

(12,982

)

$

(30,280

)

 


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

 

46



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

 

 

 

Six Months Ended September 30, 2015

 

 

 

NGL Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners LP

 

NGL Energy

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

(Parent) (1)

 

Finance Corp. (1)

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

REVENUES

 

$

 

$

 

$

6,650,251

 

$

100,621

 

$

(19,208

)

$

6,731,664

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

COST OF SALES

 

 

 

6,333,438

 

14,022

 

(19,083

)

6,328,377

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATING COSTS AND EXPENSES:

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating

 

 

 

164,790

 

43,022

 

(125

)

207,687

 

General and administrative

 

 

 

81,208

 

10,571

 

 

91,779

 

Depreciation and amortization

 

 

 

90,545

 

26,047

 

 

116,592

 

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

 

 

 

1,715

 

(3

)

 

1,712

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Income (Loss)

 

 

 

(21,445

)

6,962

 

 

(14,483

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity in earnings of unconsolidated entities

 

 

 

2,872

 

8,278

 

 

11,150

 

Interest expense

 

(35,714

)

 

(22,344

)

(4,463

)

148

 

(62,373

)

Other income, net

 

 

 

691

 

237

 

(148

)

780

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (Loss) Before Income Taxes

 

(35,714

)

 

(40,226

)

11,014

 

 

(64,926

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

INCOME TAX (PROVISION) BENEFIT

 

 

 

2,286

 

(38

)

 

2,248

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES

 

(33,730

)

 

4,210

 

 

29,520

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss)

 

(69,444

)

 

(33,730

)

10,976

 

29,520

 

(62,678

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER

 

 

 

 

 

 

 

 

 

(31,525

)

(31,525

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

 

 

 

 

 

 

 

 

 

(6,766

)

(6,766

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS

 

$

(69,444

)

$

 

$

(33,730

)

$

10,976

 

$

(8,771

)

$

(100,969

)

 


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

 

47



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Operations

(U.S. Dollars in Thousands)

 

 

 

Six Months Ended September 30, 2014

 

 

 

NGL Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners LP

 

NGL Energy

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

(Parent) (1)

 

Finance Corp. (1)

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

REVENUES

 

$

 

$

 

$

8,952,772

 

$

76,421

 

$

(53

)

$

9,029,140

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

COST OF SALES

 

 

 

8,676,881

 

36,690

 

(53

)

8,713,518

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATING COSTS AND EXPENSES:

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating

 

 

 

146,145

 

18,710

 

 

164,855

 

General and administrative

 

 

 

64,124

 

5,388

 

 

69,512

 

Depreciation and amortization

 

 

 

77,545

 

11,929

 

 

89,474

 

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

 

 

 

4,774

 

(208

)

 

4,566

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Income (Loss)

 

 

 

(16,697

)

3,912

 

 

(12,785

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity in earnings of unconsolidated entities

 

 

 

4,875

 

1,387

 

 

6,262

 

Interest expense

 

(29,593

)

 

(18,058

)

(1,517

)

23

 

(49,145

)

Other income (expense), net

 

 

 

(1,056

)

71

 

(23

)

(1,008

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (Loss) Before Income Taxes

 

(29,593

)

 

(30,936

)

3,853

 

 

(56,676

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

INCOME TAX (PROVISION) BENEFIT

 

 

 

993

 

(106

)

 

887

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES

 

(29,606

)

 

337

 

 

29,269

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss)

 

(59,199

)

 

(29,606

)

3,747

 

29,269

 

(55,789

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LESS: NET INCOME ALLOCATED TO GENERAL PARTNER

 

 

 

 

 

 

 

 

 

(20,437

)

(20,437

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS

 

 

 

 

 

 

 

 

 

(3,410

)

(3,410

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS

 

$

(59,199

)

$

 

$

(29,606

)

$

3,747

 

$

5,422

 

$

(79,636

)

 


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

 

48



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statements of Comprehensive Income (Loss)

(U.S. Dollars in Thousands)

 

 

 

Three Months Ended September 30, 2015

 

 

 

NGL Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners LP

 

NGL Energy

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

(Parent) (1)

 

Finance Corp. (1)

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(27,043

)

$

 

$

(9,130

)

$

4,837

 

$

7,184

 

$

(24,152

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive loss

 

 

 

 

(19

)

 

(19

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss)

 

$

(27,043

)

$

 

$

(9,130

)

$

4,818

 

$

7,184

 

$

(24,171

)

 


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

 

 

 

Three Months Ended September 30, 2014

 

 

 

NGL Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners LP

 

NGL Energy

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

(Parent) (2)

 

Finance Corp. (2)

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(19,224

)

$

 

$

(2,023

)

$

3,949

 

$

1,419

 

$

(15,879

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income (loss)

 

 

 

4

 

(26

)

 

(22

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss)

 

$

(19,224

)

$

 

$

(2,019

)

$

3,923

 

$

1,419

 

$

(15,901

)

 


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

 

49



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statements of Comprehensive Income (Loss)

(U.S. Dollars in Thousands)

 

 

 

Six Months Ended September 30, 2015

 

 

 

NGL Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners LP

 

NGL Energy

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

(Parent) (1)

 

Finance Corp. (1)

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(69,444

)

$

 

$

(33,730

)

$

10,976

 

$

29,520

 

$

(62,678

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive loss

 

 

 

 

(27

)

 

(27

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss)

 

$

(69,444

)

$

 

$

(33,730

)

$

10,949

 

$

29,520

 

$

(62,705

)

 


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

 

 

 

Six Months Ended September 30, 2014

 

 

 

NGL Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners LP

 

NGL Energy

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

(Parent) (2)

 

Finance Corp. (2)

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(59,199

)

$

 

$

(29,606

)

$

3,747

 

$

29,269

 

$

(55,789

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income (loss)

 

 

 

189

 

(26

)

 

163

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss)

 

$

(59,199

)

$

 

$

(29,417

)

$

3,721

 

$

29,269

 

$

(55,626

)

 


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

 

50



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)

 

 

 

Six Months Ended September 30, 2015

 

 

 

NGL Energy

 

 

 

 

 

 

 

 

 

 

 

Partners LP

 

NGL Energy

 

Guarantor

 

Non-Guarantor

 

 

 

 

 

(Parent) (1)

 

Finance Corp. (1)

 

Subsidiaries

 

Subsidiaries

 

Consolidated

 

OPERATING ACTIVITIES:

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by (used in) operating activities

 

$

(34,469

)

$

 

$

173,058

 

$

35,506

 

$

174,095

 

 

 

 

 

 

 

 

 

 

 

 

 

INVESTING ACTIVITIES:

 

 

 

 

 

 

 

 

 

 

 

Purchases of long-lived assets

 

 

 

(184,680

)

(37,596

)

(222,276

)

Acquisitions of businesses, including acquired working capital, net of cash acquired

 

 

 

(150,546

)

 

(150,546

)

Cash flows from commodity derivatives

 

 

 

43,032

 

 

43,032

 

Proceeds from sales of assets

 

 

 

3,565

 

2

 

3,567

 

Investments in unconsolidated entities

 

 

 

(2,700

)

(4,226

)

(6,926

)

Distributions of capital from unconsolidated entities

 

 

 

5,652

 

2,555

 

8,207

 

Loan for natural gas liquids facility

 

 

 

(3,913

)

 

(3,913

)

Payments on loan for natural gas liquids facility

 

 

 

3,546

 

 

3,546

 

Loan to affiliate

 

 

 

(15,621

)

 

(15,621

)

Net cash used in investing activities

 

 

 

(301,665

)

(39,265

)

(340,930

)

 

 

 

 

 

 

 

 

 

 

 

 

FINANCING ACTIVITIES:

 

 

 

 

 

 

 

 

 

 

 

Proceeds from borrowings under revolving credit facilities

 

 

 

1,311,500

 

43,200

 

1,354,700

 

Payments on revolving credit facilities

 

 

 

(963,000

)

(43,600

)

(1,006,600

)

Payments on other long-term debt

 

 

 

(2,274

)

(70

)

(2,344

)

Debt issuance costs

 

49

 

 

(180

)

(1,249

)

(1,380

)

Contributions from general partner

 

45

 

 

 

 

45

 

Contributions from noncontrolling interest owners

 

 

 

 

6,613

 

6,613

 

Distributions to partners

 

(154,824

)

 

 

 

(154,824

)

Distributions to noncontrolling interest owners

 

 

 

 

(17,780

)

(17,780

)

Taxes paid on behalf of equity incentive plan participants

 

 

 

(19,083

)

 

(19,083

)

Common unit repurchases

 

(3,650

)

 

 

 

(3,650

)

Net changes in advances with consolidated entities

 

186,776

 

 

(203,533

)

16,757

 

 

Other

 

 

 

(33

)

(79

)

(112

)

Net cash provided by financing activities

 

28,396

 

 

123,397

 

3,792

 

155,585

 

Net increase (decrease) in cash and cash equivalents

 

(6,073

)

 

(5,210

)

33

 

(11,250

)

Cash and cash equivalents, beginning of period

 

29,115

 

 

9,757

 

2,431

 

41,303

 

Cash and cash equivalents, end of period

 

$

23,042

 

$

 

$

4,547

 

$

2,464

 

$

30,053

 

 


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

 

51



Table of Contents

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements—Continued

At September 30, 2015 and March 31, 2015, and for the

Three Months and Six Months Ended September 30, 2015 and 2014

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Condensed Consolidating Statement of Cash Flows

(U.S. Dollars in Thousands)

 

 

 

Six Months Ended September 30, 2014

 

 

 

NGL Energy

 

 

 

 

 

 

 

 

 

 

 

Partners LP

 

NGL Energy

 

Guarantor

 

Non-Guarantor

 

 

 

 

 

(Parent) (1)

 

Finance Corp. (1)

 

Subsidiaries

 

Subsidiaries

 

Consolidated

 

OPERATING ACTIVITIES:

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by (used in) operating activities

 

$

(23,563

)

$

 

$

(56,019

)

$

17,947

 

$

(61,635

)

 

 

 

 

 

 

 

 

 

 

 

 

INVESTING ACTIVITIES:

 

 

 

 

 

 

 

 

 

 

 

Purchases of long-lived assets

 

 

 

(81,710

)

(1,141

)

(82,851

)

Acquisitions of businesses, including acquired working capital, net of cash acquired

 

 

 

(657,514

)

(1,250

)

(658,764

)

Cash flows from commodity derivatives

 

 

 

4,327

 

 

4,327

 

Proceeds from sales of assets

 

 

 

8,741

 

 

8,741

 

Investments in unconsolidated entities

 

 

 

(6,106

)

(20,284

)

(26,390

)

Distributions of capital from unconsolidated entities

 

 

 

2,774

 

1,875

 

4,649

 

Net cash used in investing activities

 

 

 

(729,488

)

(20,800

)

(750,288

)

 

 

 

 

 

 

 

 

 

 

 

 

FINANCING ACTIVITIES:

 

 

 

 

 

 

 

 

 

 

 

Proceeds from borrowings under revolving credit facilities

 

 

 

1,923,500

 

56,000

 

1,979,500

 

Payments on revolving credit facilities

 

 

 

(1,766,000

)

(38,000

)

(1,804,000

)

Issuance of notes

 

400,000

 

 

 

 

400,000

 

Payments on other long-term debt

 

 

 

(4,173

)

(2

)

(4,175

)

Debt issuance costs

 

(7,478

)

 

(1,720

)

 

(9,198

)

Contributions from general partner

 

395

 

 

 

 

395

 

Distributions to partners

 

(111,008

)

 

 

 

(111,008

)

Distributions to noncontrolling interest owners

 

 

 

 

(8,654

)

(8,654

)

Proceeds from sale of common units, net of offering costs

 

370,446

 

 

 

 

370,446

 

Net changes in advances with consolidated entities

 

(627,132

)

 

632,995

 

(5,863

)

 

Net cash provided by financing activities

 

25,223

 

 

784,602

 

3,481

 

813,306

 

Net increase (decrease) in cash and cash equivalents

 

1,660

 

 

(905

)

628

 

1,383

 

Cash and cash equivalents, beginning of period

 

1,181

 

 

8,728

 

531

 

10,440

 

Cash and cash equivalents, end of period

 

$

2,841

 

$

 

$

7,823

 

$

1,159

 

$

11,823

 

 


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

 

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

 

The following is a discussion of NGL Energy Partners LP’s (“we,” “us,” “our,” or the “Partnership”) financial condition and results of operations as of and for the three months and six months ended September 30, 2015. The discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10—K for the fiscal year ended March 31, 2015 (“Annual Report”).

 

Overview

 

We are a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At September 30, 2015, our operations include:

 

·                   Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals, owned and leased pipeline injection stations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned and leased barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

 

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

 

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

 

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

 

·                   Our refined products and renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the 2.0% general partner interest and a 19.6% limited partner interest in TransMontaigne Partners L.P. (“TLP”), which conducts refined products terminaling, storage, and transportation operations.

 

Crude Oil Logistics

 

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

 

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

 

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

 

 

 

Spot Price Per Barrel

 

 

 

Low

 

High

 

At Period End

 

Three Months Ended September 30,

 

 

 

 

 

 

 

2015

 

$

38.24

 

$

56.96

 

$

45.09

 

2014

 

91.16

 

105.34

 

91.16

 

 

 

 

 

 

 

 

 

Six Months Ended September 30,

 

 

 

 

 

 

 

2015

 

$

38.24

 

$

61.43

 

$

45.09

 

2014

 

91.16

 

107.26

 

91.16

 

 

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

 

Water Solutions

 

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

 

Liquids

 

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

 

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

 

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

 

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

 

 

 

Conway, Kansas

 

Mt. Belvieu, Texas

 

 

 

Spot Price Per Gallon

 

Spot Price Per Gallon

 

 

 

Low

 

High

 

At Period End

 

Low

 

High

 

At Period End

 

Three Months Ended September 30,

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

$

0.30

 

$

0.46

 

$

0.44

 

$

0.35

 

$

0.48

 

$

0.47

 

2014

 

1.00

 

1.10

 

1.03

 

0.99

 

1.11

 

1.04

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended September 30,

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

$

0.28

 

$

0.51

 

$

0.44

 

$

0.32

 

$

0.57

 

$

0.47

 

2014

 

0.96

 

1.13

 

1.03

 

0.99

 

1.13

 

1.04

 

 

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

 

 

 

Spot Price Per Gallon

 

 

 

Low

 

High

 

At Period End

 

Three Months Ended September 30,

 

 

 

 

 

 

 

2015

 

$

0.48

 

$

0.63

 

$

0.63

 

2014

 

1.21

 

1.30

 

1.22

 

 

 

 

 

 

 

 

 

Six Months Ended September 30,

 

 

 

 

 

 

 

2015

 

$

0.46

 

$

0.68

 

$

0.63

 

2014

 

1.20

 

1.30

 

1.22

 

 

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

 

Retail Propane

 

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

 

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

 

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

 

Refined Products and Renewables

 

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

 

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

 

 

 

Spot Price Per Barrel

 

 

 

Low

 

High

 

At Period End

 

Three Months Ended September 30,

 

 

 

 

 

 

 

2015

 

$

54.78

 

$

85.89

 

$

58.35

 

2014

 

105.84

 

127.68

 

108.78

 

 

 

 

 

 

 

 

 

Six Months Ended September 30,

 

 

 

 

 

 

 

2015

 

$

54.78

 

$

90.15

 

$

58.35

 

2014

 

105.84

 

131.46

 

108.78

 

 

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

 

 

 

Spot Price Per Barrel

 

 

 

Low

 

High

 

At Period End

 

Three Months Ended September 30,

 

 

 

 

 

 

 

2015

 

$

58.00

 

$

77.28

 

$

63.53

 

2014

 

111.30

 

125.16

 

111.30

 

 

 

 

 

 

 

 

 

Six Months Ended September 30,

 

 

 

 

 

 

 

2015

 

$

58.00

 

$

84.68

 

$

63.53

 

2014

 

111.30

 

128.10

 

111.30

 

 

Acquisitions

 

As described below, we completed numerous acquisitions during the year ended March 31, 2015 and the six months ended September 30, 2015. These acquisitions impact the comparability of our results of operations between our current and prior fiscal years.

 

Year Ending March 31, 2016

 

·                   In August 2015, we acquired four saltwater disposal facilities and a 50% interest in an additional saltwater disposal facility in the Delaware Basin of the Permian Basin in Texas.

 

·                   We are party to certain development agreements that provide us a right to purchase water solutions facilities developed by the other party to the agreements. During the six months ended September 30, 2015, we purchased eight water treatment and disposal facilities under these development agreements.

 

·                   During the six months ended September 30, 2015, we acquired four retail propane businesses.

 

Year Ended March 31, 2015

 

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

 

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Table of Contents

 

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

 

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

 

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

 

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

 

Summary Discussion of Operating Results for the Three Months Ended September 30, 2015

 

During the three months ended September 30, 2015, we generated operating income of $0.2 million, compared to operating income of $7.8 million during the three months ended September 30, 2014.

 

Our crude oil logistics segment generated an operating loss of $0.1 million during the three months ended September 30, 2015, compared to operating income of less than $0.1 million during the three months ended September 30, 2014. Per-barrel product margins were lower during the three months ended September 30, 2015 than during the three months ended September 30, 2014, due primarily to lower crude oil prices, which resulted in increased market pressure. This was partially offset by an increase in service revenues, which benefitted from the fact that crude oil markets were in contango during the three months ended September 30, 2015 (a condition in which forward crude prices are greater than spot prices), which enabled us to better utilize our storage assets. The decrease in operating income was also partially offset by $3.4 million of expense recorded during the three months ended September 30, 2014 related to certain employee retention and severance costs associated with the Gavilon, LLC (“Gavilon Energy”) and TransMontaigne acquisitions.

 

Our water solutions segment generated operating income of $0.2 million during the three months ended September 30, 2015, compared to operating income of $14.8 million during the three months ended September 30, 2014. The acquisition and development of new facilities contributed to operating income during the three months ended September 30, 2015, although this impact was offset by a decrease in revenues from the sale of recovered hydrocarbons resulting from the decrease in crude oil prices.

 

Our liquids segment generated operating income of $20.4 million during the three months ended September 30, 2015, compared to operating income of $10.9 million during the three months ended September 30, 2014. Product margins for butane and other products were $12.1 million higher during the three months ended September 30, 2015 than during the three months ended September 30, 2014. In addition, Sawtooth, which we acquired in February 2015, generated $3.4 million of operating income during the three months ended September 30, 2015. These increases were partially offset by a decrease of $4.7 million in product margins for sales of propane.

 

Our retail propane segment generated an operating loss of $1.8 million during the three months ended September 30, 2015, compared to an operating loss of $3.1 million during the three months ended September 30, 2014. Due to the seasonal nature of demand for propane, sales volumes of our retail propane segment typically are lower during the first and second quarters of the fiscal year than during the third and fourth quarters of the fiscal year. The primary reason for the decrease in the operating loss during the three months ended September 30, 2015 compared to the three months ended September 30, 2014 was increased margins on propane sales.

 

Our refined products and renewables segment generated an operating loss of $5.2 million during the three months ended September 30, 2015, compared to operating income of $8.8 million during the three months ended September 30, 2014. A significant portion of our refined product purchases and sales are priced based on a Gulf Coast index plus a specified differential. We use futures contracts with New York Harbor pricing to hedge the risk of price changes on our inventory valuation. Changes in the spreads between Gulf Coast and New York Harbor prices can impact the effectiveness of these futures contracts as hedges. During the three months ended September 30, 2015, Gulf Coast prices declined more than New York Harbor prices, and as a result, the futures contracts were less effective as hedges of our inventory valuation, which had an unfavorable impact on our product margins. We generally expect the spreads between the Gulf Coast and New York Harbor prices to be more consistent over the course of a year than during any individual quarter within the year. The tenor of these futures contracts, which are typically six months to one year in duration at inception, can also contribute to volatility in earnings among individual quarters within a fiscal year.

 

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Table of Contents

 

We recorded earnings from our equity method investments of $2.4 million during the three months ended September 30, 2015, compared to $3.7 million during the three months ended September 30, 2014. The decrease was due primarily to a decrease of $2.0 million in earnings from our investments in Glass Mountain Pipeline, LLC (“Glass Mountain”) and an ethanol production facility, partially offset by an increase of $1.1 million in earnings from our investments in Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and Frontera Brownsville LLC (“Frontera”).

 

We incurred interest expense of $31.6 million during the three months ended September 30, 2015, compared to $28.7 million during the three months ended September 30, 2014. The increase was due primarily to borrowings to finance acquisitions and capital expenditures.

 

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,

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

(in thousands)

 

Total revenues

 

$

3,193,195

 

$

5,380,526

 

$

6,731,664

 

$

9,029,140

 

Total cost of sales

 

3,005,826

 

5,179,465

 

6,328,377

 

8,713,518

 

Operating expenses

 

99,773

 

97,419

 

207,687

 

164,855

 

General and administrative expenses

 

29,298

 

41,639

 

91,779

 

69,512

 

Depreciation and amortization

 

56,761

 

50,099

 

116,592

 

89,474

 

Loss on disposal or impairment of assets, net

 

1,291

 

4,134

 

1,712

 

4,566

 

Operating income (loss)

 

246

 

7,770

 

(14,483

)

(12,785

)

Equity in earnings of unconsolidated entities

 

2,432

 

3,697

 

11,150

 

6,262

 

Interest expense

 

(31,571

)

(28,651

)

(62,373

)

(49,145

)

Other income (expense), net

 

1,955

 

(617

)

780

 

(1,008

)

Loss before income taxes

 

(26,938

)

(17,801

)

(64,926

)

(56,676

)

Income tax benefit

 

2,786

 

1,922

 

2,248

 

887

 

Net loss

 

(24,152

)

(15,879

)

(62,678

)

(55,789

)

Less: Net income allocated to general partner

 

(16,166

)

(11,056

)

(31,525

)

(20,437

)

Less: Net income attributable to noncontrolling interests

 

(2,891

)

(3,345

)

(6,766

)

(3,410

)

Net loss allocated to limited partners

 

$

(43,209

)

$

(30,280

)

$

(100,969

)

$

(79,636

)

 

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

 

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Table of Contents

 

Non-GAAP Financial Measures

 

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

 

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

 

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

 

The following table reconciles net loss to our EBITDA and Adjusted EBITDA (each as hereinafter defined), which are non-GAAP financial measures:

 

 

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

(in thousands)

 

Net loss

 

$

(24,152

)

$

(15,879

)

$

(62,678

)

$

(55,789

)

Net income attributable to noncontrolling interests

 

(2,891

)

(3,345

)

(6,766

)

(3,410

)

Net loss attributable to parent equity

 

 

(27,043

)

 

(19,224

)

 

(69,444

)

 

(59,199

)

Interest expense

 

29,520

 

27,929

 

58,168

 

48,446

 

Income tax benefit

 

(2,805

)

(1,933

)

(2,284

)

(898

)

Depreciation and amortization

 

53,299

 

48,366

 

107,467

 

92,716

 

EBITDA

 

52,971

 

55,138

 

93,907

 

81,065

 

Net unrealized gains on derivatives

 

(6,286

)

(13,700

)

(2,746

)

(8,690

)

Inventory valuation adjustment

 

9,197

 

 

19,355

 

 

Lower of cost or market adjustments

 

414

 

2,837

 

(5,926

)

2,837

 

Loss on disposal or impairment of assets, net

 

1,294

 

4,150

 

1,713

 

4,608

 

Equity-based compensation expense (1)

 

9,448

 

13,745

 

49,680

 

21,659

 

Adjusted EBITDA

 

$

67,038

 

$

62,170

 

$

155,983

 

$

101,479

 

 


(1)          The equity-based compensation expense in the table above may differ from the equity-based compensation expense reported in Note 11 to our condensed consolidated financial statements included in this Quarterly Report on Form 10—Q (“Quarterly Report”). Amounts reported in the table above include expense accruals for bonuses expected to be paid in common units, whereas the amounts reported in Note 11 to our condensed consolidated financial statements only include expenses associated with equity-based awards that have been formally granted.

 

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Table of Contents

 

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

 

 

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

(in thousands)

 

Reconciliation to condensed consolidated statements of operations:

 

 

 

 

 

 

 

 

 

Depreciation and amortization per EBITDA table

 

$

53,299

 

$

48,366

 

$

107,467

 

$

92,716

 

Intangible asset amortization recorded to cost of sales

 

(1,700

)

(1,984

)

(3,401

)

(4,121

)

Depreciation and amortization of unconsolidated entities

 

(5,091

)

(5,734

)

(10,125

)

(8,615

)

Depreciation and amortization attributable to noncontrolling interests

 

10,253

 

9,451

 

22,651

 

9,494

 

Depreciation and amortization per condensed consolidated statements of operations

 

$

56,761

 

$

50,099

 

$

116,592

 

$

89,474

 

 

 

 

Six Months Ended September 30,

 

 

 

 

 

 

 

2015

 

2014

 

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

Reconciliation to condensed consolidated statements of cash flows:

 

 

 

 

 

 

 

 

 

Depreciation and amortization per EBITDA table

 

$

107,467

 

$

92,716

 

 

 

 

 

Amortization of debt issuance costs recorded to interest expense

 

4,558

 

4,029

 

 

 

 

 

Depreciation and amortization of unconsolidated entities

 

(10,125

)

(8,615

)

 

 

 

 

Depreciation and amortization attributable to noncontrolling interests

 

22,651

 

9,494

 

 

 

 

 

Depreciation and amortization per condensed consolidated statements of cash flows

 

$

124,551

 

$

97,624

 

 

 

 

 

 

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

 

 

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

(in thousands)

 

Interest expense per EBITDA table

 

$

29,520

 

$

27,929

 

$

58,168

 

$

48,446

 

Interest expense attributable to noncontrolling interests

 

1,781

 

622

 

3,337

 

622

 

Gain on extinguishment of debt of unconsolidated entities

 

 

 

693

 

 

Other

 

270

 

100

 

175

 

77

 

Interest expense per condensed consolidated statements of operations

 

$

31,571

 

$

28,651

 

$

62,373

 

$

49,145

 

 

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

 

 

 

Capital Expenditures

 

 

 

Expansion (1)

 

Maintenance (2)

 

Total

 

 

 

(in thousands)

 

Three Months Ended September 30,

 

 

 

 

 

 

 

2015

 

$

87,419

 

$

15,452

 

$

102,871

 

2014

 

23,270

 

10,714

 

33,984

 

 

 

 

 

 

 

 

 

Six Months Ended September 30,

 

 

 

 

 

 

 

2015

 

$

200,532

 

$

26,006

 

$

226,538

 

2014

 

65,675

 

17,176

 

82,851

 

 


(1)          Includes expansion capital expenditures for TLP of $3.9 million and $1.0 million during the three months ended September 30, 2015 and 2014, respectively, and $9.3 million and $1.0 million during the six months ended September 30, 2015 and 2014, respectively.

 

(2)          Includes maintenance capital expenditures for TLP of $4.2 million and $0.1 million during the three months ended September 30, 2015 and 2014, respectively, and $7.1 million and $0.1 million during the six months ended September 30, 2015 and 2014, respectively.

 

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

 

 

 

Three Months Ended September 30, 2015

 

 

 

 

 

 

 

 

 

 

 

Refined

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Products

 

 

 

 

 

 

 

Crude Oil

 

Water

 

 

 

Retail

 

and

 

Corporate

 

 

 

 

 

Logistics

 

Solutions

 

Liquids

 

Propane

 

Renewables

 

and Other

 

Consolidated

 

 

 

(in thousands)

 

Operating income (loss)

 

$

(75

)

$

205

 

$

20,370

 

$

(1,765

)

$

(5,244

)

$

(13,245

)

$

246

 

Depreciation and amortization

 

10,053

 

22,416

 

2,745

 

8,909

 

11,152

 

1,486

 

56,761

 

Amortization recorded to cost of sales

 

63

 

 

261

 

 

1,376

 

 

1,700

 

Net unrealized (gains) losses on derivatives

 

1,484

 

(4,166

)

(3,331

)

(273

)

 

 

(6,286

)

Equity-based compensation expense

 

 

 

 

 

23

 

9,444

 

9,467

 

Inventory valuation adjustment

 

 

 

 

 

9,197

 

 

9,197

 

Lower of cost or market adjustments

 

14

 

 

 

 

400

 

 

414

 

Loss on disposal or impairment of assets, net

 

1,080

 

58

 

9

 

64

 

80

 

 

1,291

 

Equity in earnings (losses) of unconsolidated entities

 

474

 

(284

)

 

(94

)

2,336

 

 

2,432

 

Other income (expense), net

 

(1,812

)

479

 

105

 

228

 

(58

)

3,013

 

1,955

 

Depreciation and amortization of unconsolidated entities

 

2,492

 

319

 

 

 

2,280

 

 

5,091

 

Adjusted EBITDA attributable to noncontrolling interests

 

 

(639

)

 

(173

)

(14,418

)

 

(15,230

)

Adjusted EBITDA

 

$

13,773

 

$

18,388

 

$

20,159

 

$

6,896

 

$

7,124

 

$

698

 

$

67,038

 

 

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Table of Contents

 

 

 

Three Months Ended September 30, 2014

 

 

 

 

 

 

 

 

 

 

 

Refined

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Products

 

 

 

 

 

 

 

Crude Oil

 

Water

 

 

 

Retail

 

and

 

Corporate

 

 

 

 

 

Logistics

 

Solutions

 

Liquids

 

Propane

 

Renewables

 

and Other

 

Consolidated

 

 

 

(in thousands)

 

Operating income (loss)

 

$

38

 

$

14,792

 

$

10,929

 

$

(3,062

)

$

8,822

 

$

(23,749

)

$

7,770

 

Depreciation and amortization

 

9,240

 

17,573

 

3,384

 

7,684

 

11,917

 

301

 

50,099

 

Amortization recorded to cost of sales

 

110

 

 

495

 

 

1,353

 

26

 

1,984

 

Net unrealized gains on derivatives

 

(664

)

(12,746

)

(124

)

(166

)

 

 

(13,700

)

Equity-based compensation expense

 

 

 

 

 

 

13,745

 

13,745

 

Lower of cost or market adjustments

 

2,621

 

 

216

 

 

 

 

2,837

 

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

 

204

 

3,861

 

(109

)

259

 

1

 

(82

)

4,134

 

Equity in earnings (losses) of unconsolidated entities

 

1,918

 

(66

)

 

 

1,845

 

 

3,697

 

Other income (expense), net

 

(1,306

)

105

 

4

 

340

 

(140

)

380

 

(617

)

Depreciation and amortization of unconsolidated entities

 

2,420

 

228

 

 

 

3,086

 

 

5,734

 

Adjusted EBITDA attributable to noncontrolling interests

 

 

(89

)

 

27

 

(13,451

)

 

(13,513

)

Adjusted EBITDA

 

$

14,581

 

$

23,658

 

$

14,795

 

$

5,082

 

$

13,433

 

$

(9,379

)

$

62,170

 

 

 

 

Six Months Ended September 30, 2015

 

 

 

 

 

 

 

 

 

 

 

Refined

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Products

 

 

 

 

 

 

 

Crude Oil

 

Water

 

 

 

Retail

 

and

 

Corporate

 

 

 

 

 

Logistics

 

Solutions

 

Liquids

 

Propane

 

Renewables

 

and Other

 

Consolidated

 

 

 

(in thousands)

 

Operating income (loss)

 

$

11,885

 

$

(2,867

)

$

19,899

 

$

(2,465

)

$

27,776

 

$

(68,711

)

$

(14,483

)

Depreciation and amortization

 

20,055

 

43,262

 

7,749

 

17,615

 

25,327

 

2,584

 

116,592

 

Amortization recorded to cost of sales

 

125

 

 

522

 

 

2,754

 

 

3,401

 

Net unrealized (gains) losses on derivatives

 

714

 

(2,458

)

(740

)

(262

)

 

 

(2,746

)

Equity-based compensation expense

 

 

 

 

 

585

 

49,556

 

50,141

 

Inventory valuation adjustment

 

 

 

 

 

19,355

 

 

19,355

 

Lower of cost or market adjustments

 

(1,211

)

 

 

 

(4,715

)

 

(5,926

)

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

 

1,000

 

710

 

(191

)

113

 

80

 

 

1,712

 

Equity in earnings (losses) of unconsolidated entities

 

2,327

 

12

 

 

(159

)

8,970

 

 

11,150

 

Other income (expense), net

 

(5,760

)

783

 

209

 

626

 

255

 

4,667

 

780

 

Depreciation and amortization of unconsolidated entities

 

4,965

 

620

 

 

 

4,540

 

 

10,125

 

Adjusted EBITDA attributable to noncontrolling interests

 

 

(1,824

)

 

(125

)

(32,169

)

 

(34,118

)

Adjusted EBITDA

 

$

34,100

 

$

38,238

 

$

27,448

 

$

15,343

 

$

52,758

 

$

(11,904

)

$

155,983

 

 

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Table of Contents

 

 

 

Six Months Ended September 30, 2014

 

 

 

 

 

 

 

 

 

 

 

Refined

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Products

 

 

 

 

 

 

 

Crude Oil

 

Water

 

 

 

Retail

 

and

 

Corporate

 

 

 

 

 

Logistics

 

Solutions

 

Liquids

 

Propane

 

Renewables

 

and Other

 

Consolidated

 

 

 

(in thousands)

 

Operating income (loss)

 

$

1,501

 

$

13,885

 

$

10,016

 

$

(4,648

)

$

7,567

 

$

(41,106

)

$

(12,785

)

Depreciation and amortization

 

18,971

 

34,665

 

6,585

 

15,255

 

12,761

 

1,237

 

89,474

 

Amortization recorded to cost of sales

 

(116

)

 

988

 

 

1,614

 

1,635

 

4,121

 

Net unrealized (gains) losses on derivatives

 

(3,060

)

(6,571

)

1,140

 

(199

)

 

 

(8,690

)

Equity-based compensation expense

 

 

 

 

 

 

21,659

 

21,659

 

Lower of cost or market adjustments

 

2,621

 

 

216

 

 

 

 

2,837

 

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

 

195

 

4,347

 

(139

)

300

 

1

 

(138

)

4,566

 

Equity in earnings of unconsolidated entities

 

3,033

 

26

 

 

 

3,203

 

 

6,262

 

Other income (expense), net

 

(2,107

)

17

 

10

 

927

 

(52

)

197

 

(1,008

)

Depreciation and amortization of unconsolidated entities

 

5,179

 

228

 

 

 

3,208

 

 

8,615

 

Adjusted EBITDA attributable to noncontrolling interests

 

 

(213

)

 

92

 

(13,451

)

 

(13,572

)

Adjusted EBITDA

 

$

26,217

 

$

46,384

 

$

18,816

 

$

11,727

 

$

14,851

 

$

(16,516

)

$

101,479

 

 

Segment Operating Results for the Three Months Ended September 30, 2015 and 2014

 

Items Impacting the Comparability of Our Financial Results

 

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We have expanded our water solutions business considerably through numerous acquisitions of water treatment and disposal facilities. We expanded our liquids business through the February 2015 acquisition of Sawtooth. We expanded our retail propane business through numerous acquisitions of retail propane businesses. The results of operations of our liquids and retail propane businesses are impacted by seasonality, due primarily to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our sales volumes and revenues. For these and other reasons, our results of operations for the three months ended September 30, 2015 are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2016.

 

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Volumes

 

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

 

 

 

Three Months Ended September 30,

 

 

 

Segment

 

2015

 

2014

 

Change

 

 

 

(in thousands)

 

Crude oil logistics

 

 

 

 

 

 

 

Crude oil sold (barrels)

 

21,404

 

21,549

 

(145

)

 

 

 

 

 

 

 

 

Water solutions

 

 

 

 

 

 

 

Water received (barrels)

 

54,719

 

38,251

 

16,468

 

 

 

 

 

 

 

 

 

Liquids

 

 

 

 

 

 

 

Propane sold (gallons)

 

243,663

 

240,234

 

3,429

 

Other products sold (gallons)

 

232,227

 

197,510

 

34,717

 

 

 

 

 

 

 

 

 

Retail propane

 

 

 

 

 

 

 

Propane sold (gallons)

 

23,095

 

23,551

 

(456

)

Distillates sold (gallons)

 

3,550

 

3,434

 

116

 

 

 

 

 

 

 

 

 

Refined products and renewables

 

 

 

 

 

 

 

Refined products sold (barrels)

 

24,148

 

21,194

 

2,954

 

Renewable products sold (barrels)

 

1,308

 

1,228

 

80

 

 

Revenues and Cost of Sales by Segment

 

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

 

 

 

Three Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

Cost of

 

Product

 

 

 

Cost of

 

Product

 

 

 

Revenues

 

Sales

 

Margin

 

Revenues

 

Sales

 

Margin

 

 

 

(in thousands)

 

Crude oil logistics

 

$

1,009,852

 

$

984,993

 

$

24,859

 

$

2,121,199

 

$

2,093,744

 

$

27,455

 

Water solutions

 

47,494

 

(8,567

)

56,061

 

52,719

 

(9,439

)

62,158

 

Liquids

 

269,728

 

231,851

 

37,877

 

553,872

 

528,213

 

25,659

 

Retail propane

 

53,206

 

20,879

 

32,327

 

68,358

 

39,894

 

28,464

 

Refined products and renewables

 

1,826,187

 

1,789,943

 

36,244

 

2,607,220

 

2,550,851

 

56,369

 

Corporate and other

 

 

 

 

1,333

 

383

 

950

 

Eliminations

 

(13,272

)

(13,273

)

1

 

(24,175

)

(24,181

)

6

 

Total

 

$

3,193,195

 

$

3,005,826

 

$

187,369

 

$

5,380,526

 

$

5,179,465

 

$

201,061

 

 

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Table of Contents

 

Operating Income (Loss) by Segment

 

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

 

 

 

Three Months Ended September 30,

 

 

 

Segment

 

2015

 

2014

 

Change

 

 

 

(in thousands)

 

Crude oil logistics

 

$

(75

)

$

38

 

$

(113

)

Water solutions

 

205

 

14,792

 

(14,587

)

Liquids

 

20,370

 

10,929

 

9,441

 

Retail propane

 

(1,765

)

(3,062

)

1,297

 

Refined products and renewables

 

(5,244

)

8,822

 

(14,066

)

Corporate and other

 

(13,245

)

(23,749

)

10,504

 

Operating income

 

$

246

 

$

7,770

 

$

(7,524

)

 

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,

 

 

 

 

 

2015

 

2014 (1)

 

Change

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Crude oil sales

 

$

997,106

 

$

2,109,618

 

$

(1,112,512

)

Crude oil transportation and other

 

12,746

 

11,581

 

1,165

 

Total revenues (2)

 

1,009,852

 

2,121,199

 

(1,111,347

)

Expenses:

 

 

 

 

 

 

 

Cost of sales

 

984,993

 

2,093,744

 

(1,108,751

)

Operating expenses

 

12,851

 

12,432

 

419

 

General and administrative expenses

 

2,030

 

5,745

 

(3,715

)

Depreciation and amortization expense

 

10,053

 

9,240

 

813

 

Total expenses

 

1,009,927

 

2,121,161

 

(1,111,234

)

Segment operating income (loss)

 

$

(75

)

$

38

 

$

(113

)

 


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

 

(2)          Revenues include $2.3 million and $10.1 million of intersegment sales during the three months ended September 30, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statements of operations.

 

Revenues . Our crude oil logistics segment generated $997.1 million of revenue from crude oil sales during the three months ended September 30, 2015, selling 21.4 million barrels at an average price of $46.59 per barrel. During the three months ended September 30, 2014, our crude oil logistics segment generated $2.1 billion of revenue from crude oil sales, selling 21.5 million barrels at an average price of $97.90 per barrel. The decrease in revenue per barrel was due primarily to the sharp decline in crude oil prices after September 30, 2014.

 

Crude oil transportation and other revenues were $12.7 million during the three months ended September 30, 2015, compared to $11.6 million during the three months ended September 30, 2014. The increase is due primarily to crude oil markets being in contango during the three months ended September 30, 2015 (a condition in which forward crude prices are greater than spot prices), which allowed us to generate revenue from leasing our owned storage and subleasing our leased storage.

 

Cost of Sales . Our cost of crude oil sold was $985.0 million during the three months ended September 30, 2015, as we sold 21.4 million barrels at an average cost of $46.02 per barrel. Our cost of sales during the three months ended September 30, 2015 was increased by $1.5 million of net unrealized losses on derivatives. During the three months ended September 30, 2014, our cost of crude oil sold was $2.1 billion, as we sold 21.5 million barrels at an average cost of $97.16 per barrel. Our cost of sales during the

 

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Table of Contents

 

three months ended September 30, 2014 was reduced by $0.7 million of net unrealized gains on derivatives. The following table summarizes our product margins for crude oil sales (in thousands, except per barrel amounts) for the periods indicated:

 

 

 

Three Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Crude oil sales revenues

 

$

997,106

 

$

2,109,618

 

Crude oil cost of sales

 

(984,993

)

(2,093,744

)

Crude oil product margin

 

$

12,113

 

$

15,874

 

 

 

 

 

 

 

Crude oil sold (barrels)

 

21,404

 

21,549

 

 

 

 

 

 

 

Product margin per barrel

 

$

0.57

 

$

0.74

 

 

Per-barrel product margins were lower during the three months ended September 30, 2015 than during the three months ended September 30, 2014 due primarily to lower crude oil prices, which resulted in increased market pressure.

 

Operating Expenses . Our crude oil logistics segment incurred operating expenses of $12.9 million during the three months ended September 30, 2015, compared to $12.4 million during the three months ended September 30, 2014. This increase was due primarily to higher repair and maintenance expense due to the timing of repairs and to losses on asset retirements, partially offset by lower incentive compensation expense, as incentive compensation expense for the three months ended September 30, 2015 is reported within “corporate and other,” rather than within the crude oil logistics segment, since we expect to pay these bonuses in common units.

 

General and Administrative Expenses . Our crude oil logistics segment incurred general and administrative expenses of $2.0 million during the three months ended September 30, 2015, compared to $5.7 million during the three months ended September 30, 2014. General and administrative expenses during the three months ended September 30, 2014 included $2.2 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses were paid in December 2014. General and administrative expenses during the three months ended September 30, 2014 were also increased by $1.2 million of compensation expense related to termination benefits for certain TransMontaigne employees.

 

Depreciation and Amortization Expense . Our crude oil logistics segment incurred depreciation and amortization expense of $10.1 million during the three months ended September 30, 2015, compared to $9.2 million during the three months ended September 30, 2014.

 

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Water Solutions

 

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

 

 

 

Three Months Ended September 30,

 

 

 

 

 

2015

 

2014

 

Change

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Service fees

 

$

35,203

 

$

24,238

 

$

10,965

 

Recovered hydrocarbons

 

10,746

 

23,334

 

(12,588

)

Water transportation

 

 

5,147

 

(5,147

)

Other revenues

 

1,545

 

 

1,545

 

Total revenues

 

47,494

 

52,719

 

(5,225

)

Expenses:

 

 

 

 

 

 

 

Cost of sales—derivative gain (1)

 

(8,567

)

(12,373

)

3,806

 

Cost of sales—other

 

 

2,934

 

(2,934

)

Operating expenses

 

32,755

 

29,019

 

3,736

 

General and administrative expenses

 

685

 

774

 

(89

)

Depreciation and amortization expense

 

22,416

 

17,573

 

4,843

 

Total expenses

 

47,289

 

37,927

 

9,362

 

Segment operating income

 

$

205

 

$

14,792

 

$

(14,587

)

 


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

 

The following tables summarize activity separated among the following categories:

 

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

 

·                   facilities we developed after June 30, 2014, which we refer to below as “recently developed facilities”; and

 

·                   facilities we acquired after June 30, 2014, which we refer to below as “recently acquired facilities”.

 

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

 

 

 

Three Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

Water

 

Fees Per

 

 

 

Water

 

Fees Per

 

 

 

Service

 

Barrels

 

Water Barrel

 

Service

 

Barrels

 

Water Barrel

 

 

 

Fees

 

Processed

 

Processed

 

Fees

 

Processed

 

Processed

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Existing facilities

 

$

22,651

 

31,891

 

$

0.71

 

$

24,238

 

38,251

 

$

0.63

 

Recently developed facilities

 

4,440

 

7,561

 

0.59

 

 

 

 

Recently acquired facilities

 

8,112

 

15,267

 

0.53

 

 

 

 

Total

 

$

35,203

 

54,719

 

0.64

 

$

24,238

 

38,251

 

0.63

 

 

The decrease in the volume processed at our existing facilities during the three months ended September 30, 2015 compared to the three months ended September 30, 2014 was due primarily to a slowdown in customer production as a result of the lower crude oil prices, and was also due in part to migration of volumes from existing facilities to recently developed and recently acquired facilities due to the location of the facilities.

 

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

 

 

 

Three Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

Recovered

 

Water

 

Revenue Per

 

Recovered

 

Water

 

Revenue Per

 

 

 

Hydrocarbon

 

Barrels

 

Water Barrel

 

Hydrocarbon

 

Barrels

 

Water Barrel

 

 

 

Revenue

 

Processed

 

Processed

 

Revenue

 

Processed

 

Processed

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Existing facilities

 

$

6,526

 

31,891

 

$

0.20

 

$

23,334

 

38,251

 

$

0.61

 

Recently developed facilities

 

1,415

 

7,561

 

0.19

 

 

 

 

Recently acquired facilities

 

2,805

 

15,267

 

0.18

 

 

 

 

Total

 

$

10,746

 

54,719

 

0.20

 

$

23,334

 

38,251

 

0.61

 

 

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

 

Our water solutions segment generated $5.1 million of water transportation revenue during the three months ended September 30, 2014. These revenues related to our water transportation business, which we sold during September 2014.

 

Cost of Sales . We enter into derivatives in our water solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expect to recover when processing the wastewater. Our cost of sales during the three months ended September 30, 2015 was reduced by $4.2 million of net unrealized gains on derivatives and $4.4 million of net realized gains on derivatives. Our cost of sales during the three months ended September 30, 2014 was reduced by $12.7 million of net unrealized gains on derivatives and increased by $0.3 million of net realized losses on derivatives.

 

Our other cost of sales was $2.9 million during the three months ended September 30, 2014. These costs related primarily to our water transportation business, which we sold during September 2014.

 

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

 

 

 

Three Months Ended September 30,

 

 

 

 

 

2015

 

2014

 

Change

 

 

 

(in thousands)

 

Existing facilities

 

$

21,813

 

$

29,019

 

$

(7,206

)

Recently developed facilities

 

2,765

 

 

2,765

 

Recently acquired facilities

 

8,177

 

 

8,177

 

Total

 

$

32,755

 

$

29,019

 

$

3,736

 

 

The decrease in operating expenses for existing facilities was due primarily to a loss of $4.0 million related to the sale of our water transportation business during September 2014, and to lower operating costs of water disposal wells at existing facilities due to lower volumes processed.

 

General and Administrative Expenses . Our water solutions segment incurred general and administrative expenses of $0.7 million during the three months ended September 30, 2015, compared to $0.8 million during the three months ended September 30, 2014.

 

Depreciation and Amortization Expense . Our water solutions segment incurred depreciation and amortization expense of $22.4 million during the three months ended September 30, 2015, compared to $17.6 million during the three months ended September 30, 2014. Of this increase, $3.0 million related to recently acquired facilities and $0.7 million related to recently developed facilities.

 

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Liquids

 

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

 

 

 

Three Months Ended September 30,

 

 

 

 

 

2015

 

2014 (1)

 

Change

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Propane sales

 

$

98,770

 

$

240,933

 

$

(142,163

)

Other product sales

 

160,836

 

306,660

 

(145,824

)

Other revenues

 

10,122

 

6,279

 

3,843

 

Total revenues (2)

 

269,728

 

553,872

 

(284,144

)

Expenses:

 

 

 

 

 

 

 

Cost of sales—propane

 

95,903

 

233,390

 

(137,487

)

Cost of sales—other products

 

132,179

 

290,119

 

(157,940

)

Cost of sales—other

 

3,769

 

4,704

 

(935

)

Operating expenses

 

12,330

 

9,183

 

3,147

 

General and administrative expenses

 

2,432

 

2,163

 

269

 

Depreciation and amortization expense

 

2,745

 

3,384

 

(639

)

Total expenses

 

249,358

 

542,943

 

(293,585

)

Segment operating income

 

$

20,370

 

$

10,929

 

$

9,441

 

 


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

 

(2)          Revenues include $10.8 million and $14.1 million of intersegment sales during the three months ended September 30, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statements of operations.

 

Revenues . Our liquids segment generated $98.8 million of wholesale propane sales revenue during the three months ended September 30, 2015, selling 243.7 million gallons at an average price of $0.41 per gallon. During the three months ended September 30, 2014, our liquids segment generated $240.9 million of wholesale propane sales revenue, selling 240.2 million gallons at an average price of $1.00 per gallon.

 

Our liquids segment generated $160.8 million of other wholesale products sales revenue during the three months ended September 30, 2015, selling 232.2 million gallons at an average price of $0.69 per gallon. During the three months ended September 30, 2014, our liquids segment generated $306.7 million of other wholesale products sales revenue, selling 197.5 million gallons at an average price of $1.55 per gallon. The increase in the volume of other wholesale products sold was due to expanded operations.

 

Our liquids segment generated $10.1 million of other revenues during the three months ended September 30, 2015, compared to $6.3 million during the three months ended September 30, 2014. This revenue includes storage income and income generated from the operation of a terminal for a customer. This increase was due primarily to $5.2 million of revenue related to Sawtooth, which we acquired in February 2015.

 

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Cost of Sales . Our cost of wholesale propane sales was $95.9 million during the three months ended September 30, 2015, as we sold 243.7 million gallons at an average cost of $0.39 per gallon. Our cost of wholesale propane sales during the three months ended September 30, 2015 was reduced by less than $0.1 million of net unrealized gains on derivatives. During the three months ended September 30, 2014, our cost of wholesale propane sales was $233.4 million, as we sold 240.2 million gallons at an average cost of $0.97 per gallon. Our cost of wholesale propane sales during the three months ended September 30, 2014 was increased by $1.9 million of net unrealized losses on derivatives. The following table summarizes our product margins for propane sales (in thousands, except per gallon amounts) for the periods indicated:

 

 

 

Three Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Propane revenues

 

$

98,770

 

$

240,933

 

Propane cost of sales

 

(95,903

)

(233,390

)

Propane product margin

 

$

2,867

 

$

7,543

 

 

 

 

 

 

 

Propane sold (gallons)

 

243,663

 

240,234

 

 

 

 

 

 

 

Product margin per gallon

 

$

0.012

 

$

0.031

 

 

Propane prices declined during the three months ended September 30, 2015, which had an adverse impact on product margins.

 

Our cost of sales of other products was $132.2 million during the three months ended September 30, 2015, as we sold 232.2 million gallons at an average cost of $0.57 per gallon. Our cost of sales of other products during the three months ended September 30, 2015 was reduced by $3.3 million of net unrealized gains on derivatives. During the three months ended September 30, 2014, our cost of sales of other products was $290.1 million, as we sold 197.5 million gallons at an average cost of $1.47 per gallon. Our cost of sales of other products during the three months ended September 30, 2014 was reduced by $2.2 million of net unrealized gains on derivatives. The following table summarizes our per gallon product margins (in thousands, except per gallon amounts) for the periods indicated:

 

 

 

Three Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Other products revenues

 

$

160,836

 

$

306,660

 

Other products cost of sales

 

(132,179

)

(290,119

)

Other products product margin

 

$

28,657

 

$

16,541

 

 

 

 

 

 

 

Other products sold (gallons)

 

232,227

 

197,510

 

 

 

 

 

 

 

Product margin per gallon

 

$

0.123

 

$

0.084

 

 

Product margins during the three months ended September 30, 2015 benefitted from a high level of butane supply in the market, which lowered our product cost.

 

Operating Expenses . Our liquids segment incurred operating expenses of $12.3 million during the three months ended September 30, 2015, compared to $9.2 million during the three months ended September 30, 2014. The increase in operating expenses was due primarily to $1.1 million of expenses related to Sawtooth, which we acquired in February 2015, and to increased compensation expense.

 

General and Administrative Expenses . Our liquids segment incurred general and administrative expenses of $2.4 million during the three months ended September 30, 2015, compared to $2.2 million during the three months ended September 30, 2014.

 

Depreciation and Amortization Expense . Our liquids segment incurred depreciation and amortization expense of $2.7 million during the three months ended September 30, 2015, compared to $3.4 million during the three months ended September 30, 2014.

 

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Retail Propane

 

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

 

 

 

Three Months Ended September 30,

 

 

 

 

 

2015

 

2014

 

Change

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Propane sales

 

$

36,119

 

$

48,552

 

$

(12,433

)

Distillate sales

 

7,678

 

11,530

 

(3,852

)

Other revenues

 

9,409

 

8,276

 

1,133

 

Total revenues

 

53,206

 

68,358

 

(15,152

)

Expenses:

 

 

 

 

 

 

 

Cost of sales—propane

 

11,921

 

27,434

 

(15,513

)

Cost of sales—distillates

 

5,783

 

9,840

 

(4,057

)

Cost of sales—other

 

3,175

 

2,620

 

555

 

Operating expenses

 

22,485

 

21,205

 

1,280

 

General and administrative expenses

 

2,698

 

2,637

 

61

 

Depreciation and amortization expense

 

8,909

 

7,684

 

1,225

 

Total expenses

 

54,971

 

71,420

 

(16,449

)

Segment operating loss

 

$

(1,765

)

$

(3,062

)

$

1,297

 

 

Revenues . Our retail propane segment generated revenue of $36.1 million from propane sales during the three months ended September 30, 2015, selling 23.1 million gallons at an average price of $1.56 per gallon. During the three months ended September 30, 2014, our retail propane segment generated $48.6 million of revenue from propane sales, selling 23.6 million gallons at an average price of $2.06 per gallon.

 

Our retail propane segment generated revenue of $7.7 million from distillate sales during the three months ended September 30, 2015, selling 3.6 million gallons at an average price of $2.16 per gallon. During the three months ended September 30, 2014, our retail propane segment generated $11.5 million of revenue from distillate sales, selling 3.4 million gallons at an average price of $3.36 per gallon.

 

Cost of Sales . Our cost of retail propane sales was $11.9 million during the three months ended September 30, 2015, as we sold 23.1 million gallons at an average cost of $0.52 per gallon. During the three months ended September 30, 2014, our cost of retail propane sales was $27.4 million, as we sold 23.6 million gallons at an average cost of $1.16 per gallon. The following table summarizes our product margins for retail propane sales (in thousands, except per gallon amounts) for the periods indicated:

 

 

 

Three Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Propane revenues

 

$

36,119

 

$

48,552

 

Propane cost of sales

 

(11,921

)

(27,434

)

Propane product margin

 

$

24,198

 

$

21,118

 

 

 

 

 

 

 

Propane sold (gallons)

 

23,095

 

23,551

 

 

 

 

 

 

 

Product margin per gallon

 

$

1.05

 

$

0.90

 

 

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Our cost of distillate sales was $5.8 million during the three months ended September 30, 2015, as we sold 3.6 million gallons at an average cost of $1.63 per gallon. During the three months ended September 30, 2014, our cost of distillate sales was $9.8 million, as we sold 3.4 million gallons at an average cost of $2.87 per gallon. The following table summarizes our product margins for distillate sales (in thousands, except per gallon amounts) for the periods indicated:

 

 

 

Three Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Distillate revenues

 

$

7,678

 

$

11,530

 

Distillate cost of sales

 

(5,783

)

(9,840

)

Distillate product margin

 

$

1,895

 

$

1,690

 

 

 

 

 

 

 

Distillate sold (gallons)

 

3,550

 

3,434

 

 

 

 

 

 

 

Product margin per gallon

 

$

0.53

 

$

0.49

 

 

Operating Expenses . Our retail propane segment incurred operating expenses of $22.5 million during the three months ended September 30, 2015, compared to $21.2 million during the three months ended September 30, 2014. The increase in operating expenses was due primarily to increased employee compensation expense in support of the growth of our business.

 

General and Administrative Expenses . Our retail propane segment incurred general and administrative expenses of $2.7 million during the three months ended September 30, 2015, compared to $2.6 million during the three months ended September 30, 2014.

 

Depreciation and Amortization Expense . Our retail propane segment incurred depreciation and amortization expense of $8.9 million during the three months ended September 30, 2015, compared to $7.7 million during the three months ended September 30, 2014.

 

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,

 

 

 

 

 

2015

 

2014 (1)

 

Change

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Refined products sales (2)

 

$

1,704,259

 

$

2,466,389

 

$

(762,130

)

Renewables sales

 

93,189

 

116,825

 

(23,636

)

Service fees

 

28,739

 

24,006

 

4,733

 

Total revenues

 

1,826,187

 

2,607,220

 

(781,033

)

Expenses:

 

 

 

 

 

 

 

Cost of sales—refined products

 

1,696,664

 

2,436,468

 

(739,804

)

Cost of sales—renewables

 

93,279

 

114,383

 

(21,104

)

Operating expenses

 

25,538

 

29,838

 

(4,300

)

General and administrative expenses

 

4,798

 

5,792

 

(994

)

Depreciation and amortization expense

 

11,152

 

11,917

 

(765

)

Total expenses

 

1,831,431

 

2,598,398

 

(766,967

)

Segment operating income (loss)

 

$

(5,244

)

$

8,822

 

$

(14,066

)

 


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

 

(2)          Revenues include $0.3 million of intersegment sales during the three months ended September 30, 2015 that are eliminated in our condensed consolidated statement of operations.

 

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Revenues . Our refined products sales revenue was $1.7 billion during the three months ended September 30, 2015, selling 24.1 million barrels at an average price of $70.58 per barrel. Our refined products sales revenue was $2.5 billion during the three months ended September 30, 2014, selling 21.2 million barrels at an average price of $116.37 per barrel. The increase in revenues resulting from higher sales volumes was offset by a sharp decline in product prices.  The increase in volumes was due primarily to the purchase of certain pipeline capacity allocations from other shippers during the second half of the fiscal year ended March 31, 2015.

 

Our renewables sales revenue was $93.2 million during the three months ended September 30, 2015, selling 1.3 million barrels at an average price of $71.25 per barrel. Our renewables sales revenue was $116.8 million during the three months ended September 30, 2014, selling 1.2 million barrels at an average price of $95.13 per barrel.

 

Our refined products and renewables segment generated $28.7 million of service fee revenue during the three months ended September 30, 2015, compared to $24.0 million during the three months ended September 30, 2014. The increase in service fee revenue was due primarily to the fact that one of TLP’s terminal facilities was temporarily out of service during the three months ended September 30, 2014, the contracting of additional available capacity to a third party for a three-year term beginning in May 2015, and the transfer of a contract obligation from NGL to a third party during the fiscal year ended March 31, 2015.

 

Cost of Sales . Our cost of refined products sales was $1.7 billion during the three months ended September 30, 2015, as we sold 24.1 million barrels at an average cost of $70.26 per barrel. Our cost of refined products sales was $2.4 billion during the three months ended September 30, 2014, as we sold 21.2 million barrels at an average cost of $114.96 per barrel. The following table summarizes our refined product margins (in thousands, except per barrel and per gallon amounts) for the periods indicated:

 

 

 

Three Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Refined products revenues

 

$

1,704,259

 

$

2,466,389

 

Refined products cost of sales

 

(1,696,664

)

(2,436,468

)

Refined products product margin

 

$

7,595

 

$

29,921

 

 

 

 

 

 

 

Refined products sold (barrels)

 

24,148

 

21,194

 

 

 

 

 

 

 

Product margin per barrel

 

$

0.315

 

$

1.412

 

Product margin per gallon

 

$

0.007

 

$

0.034

 

 

A significant portion of our refined product purchases and sales are priced based on a Gulf Coast index plus a specified differential. We use futures contracts with New York Harbor pricing to hedge the risk of price changes on our inventory valuation. Changes in the spreads between Gulf Coast and New York Harbor prices can impact the effectiveness of these futures contracts as hedges. During the three months ended September 30, 2015, Gulf Coast prices declined more than New York Harbor prices, and as a result, the futures contracts were less effective as hedges of our inventory valuation, which had an unfavorable impact on our product margins. We generally expect the spreads between the Gulf Coast and New York Harbor prices to be more consistent over the course of a year than during any individual quarter within the year. The tenor of these futures contracts, which are typically six months to one year in duration at inception, can also contribute to volatility in earnings among individual quarters within a fiscal year.

 

Our cost of renewables sales was $93.3 million during the three months ended September 30, 2015, as we sold 1.3 million barrels at an average cost of $71.31 per barrel. Our cost of renewables sales was $114.4 million during the three months ended September 30, 2014, as we sold 1.2 million barrels at an average cost of $93.15 per barrel. The following table summarizes our renewables product margins (in thousands, except per barrel and per gallon amounts) for the periods indicated:

 

 

 

Three Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Renewables revenues

 

$

93,189

 

$

116,825

 

Renewables cost of sales

 

(93,279

)

(114,383

)

Renewables product margin (loss)

 

$

(90

)

$

2,442

 

 

 

 

 

 

 

Renewable products sold (barrels)

 

1,308

 

1,228

 

 

 

 

 

 

 

Product margin (loss) per barrel

 

$

(0.069

)

$

1.989

 

Product margin (loss) per gallon

 

$

(0.002

)

$

0.047

 

 

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Per-barrel product margins were lower during the three months ended September 30, 2015 than during the three months ended September 30, 2014 due primarily to lower renewables prices caused by increased import activity.

 

Operating Expenses . Our refined products and renewables segment incurred operating expenses of $25.5 million during the three months ended September 30, 2015, compared to $29.8 million during the three months ended September 30, 2014. This decrease was due primarily to lower compensation expense related to post-acquisition synergies.

 

General and Administrative Expenses . Our refined products and renewables segment incurred general and administrative expenses of $4.8 million during the three months ended September 30, 2015, compared to $5.8 million during the three months ended September 30, 2014. General and administrative expenses during the three months ended September 30, 2014 were increased by $1.5 million of compensation expense related to termination benefits for certain TransMontaigne employees.

 

Depreciation and Amortization Expense . Our refined products and renewables segment incurred depreciation and amortization expense of $11.2 million during the three months ended September 30, 2015, compared to $11.9 million during the three months ended September 30, 2014.

 

Corporate and Other

 

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

 

 

 

Three Months Ended September 30,

 

 

 

 

 

2015

 

2014

 

Change

 

 

 

(in thousands)

 

Incentive compensation expense

 

$

(4,278

)

$

(13,817

)

$

9,539

 

Acquisition expenses

 

(566

)

(3,230

)

2,664

 

Other corporate expenses

 

(8,401

)

(6,702

)

(1,699

)

Total

 

$

(13,245

)

$

(23,749

)

$

10,504

 

 

The expenses shown in the table above for incentive compensation include cash-based and equity-based compensation. Such incentive compensation expenses were lower during the three months ended September 30, 2015 than during the three months ended September 30, 2014, due primarily to lower expenses associated with discretionary employee bonuses.

 

The expenses shown in the table above for acquisitions relate primarily to legal and advisory costs. We incurred $3.0 million of such expenses during the three months ended September 30, 2014 related to our acquisition of TransMontaigne.

 

The increase in other corporate expenses was due to the continued growth of our business.

 

Segment Operating Results for the Six Months Ended September 30, 2015 and 2014

 

Items Impacting the Comparability of Our Financial Results

 

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We have expanded our water solutions business considerably through numerous acquisitions of water treatment and disposal facilities. We expanded our liquids business through the February 2015 acquisition of Sawtooth. We expanded our retail propane business through numerous acquisitions of retail propane businesses. Our refined products and renewables businesses were significantly expanded with our July 2014 acquisition of TransMontaigne. The results of operations of our liquids and retail propane businesses are impacted by seasonality, due primarily to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our sales volumes and revenues. For these and other reasons, our results of operations for the six months ended September 30, 2015 are not necessarily indicative of the results of operations to be expected for future periods or for the full fiscal year ending March 31, 2016.

 

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Volumes

 

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

 

 

 

Six Months Ended September 30,

 

 

 

Segment

 

2015

 

2014

 

Change

 

 

 

(in thousands)

 

Crude oil logistics

 

 

 

 

 

 

 

Crude oil sold (barrels)

 

45,087

 

40,806

 

4,281

 

 

 

 

 

 

 

 

 

Water solutions

 

 

 

 

 

 

 

Water received (barrels)

 

109,195

 

65,689

 

43,506

 

 

 

 

 

 

 

 

 

Liquids

 

 

 

 

 

 

 

Propane sold (gallons)

 

471,615

 

423,992

 

47,623

 

Other products sold (gallons)

 

424,214

 

384,235

 

39,979

 

 

 

 

 

 

 

 

 

Retail propane

 

 

 

 

 

 

 

Propane sold (gallons)

 

47,502

 

47,142

 

360

 

Distillates sold (gallons)

 

8,643

 

8,712

 

(69

)

 

 

 

 

 

 

 

 

Refined products and renewables

 

 

 

 

 

 

 

Refined products sold (barrels)

 

45,075

 

29,094

 

15,981

 

Renewable products sold (barrels)

 

2,683

 

2,490

 

193

 

 

Revenues and Cost of Sales by Segment

 

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

 

 

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

Cost of

 

Product

 

 

 

Cost of

 

Product

 

 

 

Revenues

 

Sales

 

Margin

 

Revenues

 

Sales

 

Margin

 

 

 

(in thousands)

 

Crude oil logistics

 

$

2,341,584

 

$

2,280,933

 

$

60,651

 

$

4,060,257

 

$

4,001,158

 

$

59,099

 

Water solutions

 

101,787

 

(4,960

)

106,747

 

100,033

 

1,134

 

98,899

 

Liquids

 

532,229

 

477,643

 

54,586

 

1,070,393

 

1,031,563

 

38,830

 

Retail propane

 

117,653

 

50,443

 

67,210

 

146,260

 

87,418

 

58,842

 

Refined products and renewables

 

3,669,362

 

3,555,256

 

114,106

 

3,724,717

 

3,665,164

 

59,553

 

Corporate and other

 

 

 

 

2,794

 

2,371

 

423

 

Eliminations

 

(30,951

)

(30,938

)

(13

)

(75,314

)

(75,290

)

(24

)

Total

 

$

6,731,664

 

$

6,328,377

 

$

403,287

 

$

9,029,140

 

$

8,713,518

 

$

315,622

 

 

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Operating Income (Loss) by Segment

 

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

 

 

 

Six Months Ended September 30,

 

 

 

Segment

 

2015

 

2014

 

Change

 

 

 

(in thousands)

 

Crude oil logistics

 

$

11,885

 

$

1,501

 

$

10,384

 

Water solutions

 

(2,867

)

13,885

 

(16,752

)

Liquids

 

19,899

 

10,016

 

9,883

 

Retail propane

 

(2,465

)

(4,648

)

2,183

 

Refined products and renewables

 

27,776

 

7,567

 

20,209

 

Corporate and other

 

(68,711

)

(41,106

)

(27,605

)

Operating loss

 

$

(14,483

)

$

(12,785

)

$

(1,698

)

 

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,

 

 

 

 

 

2015

 

2014 (1)

 

Change

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Crude oil sales

 

$

2,309,889

 

$

4,038,673

 

$

(1,728,784

)

Crude oil transportation and other

 

31,695

 

21,584

 

10,111

 

Total revenues (2)

 

2,341,584

 

4,060,257

 

(1,718,673

)

Expenses:

 

 

 

 

 

 

 

Cost of sales

 

2,280,933

 

4,001,158

 

(1,720,225

)

Operating expenses

 

24,601

 

28,417

 

(3,816

)

General and administrative expenses

 

4,110

 

10,210

 

(6,100

)

Depreciation and amortization expense

 

20,055

 

18,971

 

1,084

 

Total expenses

 

2,329,699

 

4,058,756

 

(1,729,057

)

Segment operating income

 

$

11,885

 

$

1,501

 

$

10,384

 

 


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

 

(2)          Revenues include $6.2 million and $19.8 million of intersegment sales during the six months ended September 30, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statements of operations.

 

Revenues . Our crude oil logistics segment generated $2.3 billion of revenue from crude oil sales during the six months ended September 30, 2015, selling 45.1 million barrels at an average price of $51.23 per barrel. During the six months ended September 30, 2014, our crude oil logistics segment generated $4.0 billion of revenue from crude oil sales, selling 40.8 million barrels at an average price of $98.97 per barrel. The decrease in revenue per barrel was due primarily to the sharp decline in crude oil prices after September 30, 2014. The increase in our sales volumes was due to expanded operations.

 

Crude oil transportation and other revenues were $31.7 million during the six months ended September 30, 2015, compared to $21.6 million during the six months ended September 30, 2014. The increase is due primarily to crude oil markets being in contango during the six months ended September 30, 2015 (a condition in which forward crude prices are greater than spot prices), which allowed us to generate revenue from leasing our owned storage and subleasing our leased storage.

 

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Cost of Sales . Our cost of crude oil sold was $2.3 billion during the six months ended September 30, 2015, as we sold 45.1 million barrels at an average cost of $50.59 per barrel. Our cost of sales during the six months ended September 30, 2015 was increased by $0.7 million of net unrealized losses on derivatives. During the six months ended September 30, 2014, our cost of crude oil sold was $4.0 billion, as we sold 40.8 million barrels at an average cost of $98.05 per barrel. Our cost of sales during the six months ended September 30, 2014 was reduced by $3.1 million of net unrealized gains on derivatives. The following table summarizes our product margins for crude oil sales (in thousands, except per barrel amounts) for the periods indicated:

 

 

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Crude oil sales revenues

 

$

2,309,889

 

$

4,038,673

 

Crude oil cost of sales

 

(2,280,933

)

(4,001,158

)

Crude oil product margin

 

$

28,956

 

$

37,515

 

 

 

 

 

 

 

Crude oil sold (barrels)

 

45,087

 

40,806

 

 

 

 

 

 

 

Product margin per barrel

 

$

0.64

 

$

0.92

 

 

Per-barrel product margins were lower during the six months ended September 30, 2015 than during the six months ended September 30, 2014 due primarily to lower crude oil prices, which resulted in increased market pressure.

 

Operating Expenses . Our crude oil logistics segment incurred operating expenses of $24.6 million during the six months ended September 30, 2015, compared to $28.4 million during the six months ended September 30, 2014. This decrease was due primarily to lower incentive compensation expense, as incentive compensation expense for the six months ended September 30, 2015 is reported within “corporate and other,” rather than within the crude oil logistics segment, since we expect to pay these bonuses in common units.

 

General and Administrative Expenses . Our crude oil logistics segment incurred general and administrative expenses of $4.1 million during the six months ended September 30, 2015, compared to $10.2 million during the six months ended September 30, 2014. General and administrative expenses during the six months ended September 30, 2014 included $4.3 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses were paid in December 2014. General and administrative expenses during the six months ended September 30, 2014 were also increased by $1.2 million of compensation expense related to termination benefits for certain TransMontaigne employees.

 

Depreciation and Amortization Expense . Our crude oil logistics segment incurred depreciation and amortization expense of $20.1 million during the six months ended September 30, 2015, compared to $19.0 million during the six months ended September 30, 2014.

 

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Water Solutions

 

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

 

 

 

Six Months Ended September 30,

 

 

 

 

 

2015

 

2014

 

Change

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Service fees

 

$

71,941

 

$

41,939

 

$

30,002

 

Recovered hydrocarbons

 

26,564

 

47,349

 

(20,785

)

Water transportation

 

 

10,745

 

(10,745

)

Other revenues

 

3,282

 

 

3,282

 

Total revenues

 

101,787

 

100,033

 

1,754

 

Expenses:

 

 

 

 

 

 

 

Cost of sales—derivative gain (1)

 

(4,960

)

(5,070

)

110

 

Cost of sales—other

 

 

6,204

 

(6,204

)

Operating expenses

 

64,949

 

48,748

 

16,201

 

General and administrative expenses

 

1,403

 

1,601

 

(198

)

Depreciation and amortization expense

 

43,262

 

34,665

 

8,597

 

Total expenses

 

104,654

 

86,148

 

18,506

 

Segment operating income (loss)

 

$

(2,867

)

$

13,885

 

$

(16,752

)

 


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

 

The following tables summarize activity separated among the following categories:

 

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

 

·                   facilities we developed after March 31, 2014, which we refer to below as “recently developed facilities”; and

 

·                   facilities we acquired after March 31, 2014, which we refer to below as “recently acquired facilities”.

 

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

 

 

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

Water

 

Fees Per

 

 

 

Water

 

Fees Per

 

 

 

Service

 

Barrels

 

Water Barrel

 

Service

 

Barrels

 

Water Barrel

 

 

 

Fees

 

Processed

 

Processed

 

Fees

 

Processed

 

Processed

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Existing facilities

 

$

39,686

 

50,669

 

$

0.78

 

$

37,376

 

58,639

 

$

0.64

 

Recently developed facilities

 

7,898

 

13,466

 

0.59

 

 

 

 

Recently acquired facilities

 

24,357

 

45,060

 

0.54

 

4,563

 

7,050

 

0.65

 

Total

 

$

71,941

 

109,195

 

0.66

 

$

41,939

 

65,689

 

0.64

 

 

The decrease in the volume processed at our existing facilities during the six months ended September 30, 2015 compared to the six months ended September 30, 2014 was due primarily to a slowdown in customer production as a result of the lower crude oil prices, and was also due in part to migration of volumes from existing facilities to recently developed and recently acquired facilities due to the location of the facilities.

 

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Table of Contents

 

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

 

 

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

Recovered

 

Water

 

Revenue Per

 

Recovered

 

Water

 

Revenue Per

 

 

 

Hydrocarbon

 

Barrels

 

Water Barrel

 

Hydrocarbon

 

Barrels

 

Water Barrel

 

 

 

Revenue

 

Processed

 

Processed

 

Revenue

 

Processed

 

Processed

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Existing facilities

 

$

15,207

 

50,669

 

$

0.30

 

$

44,831

 

58,639

 

$

0.76

 

Recently developed facilities

 

3,459

 

13,466

 

0.26

 

 

 

 

Recently acquired facilities

 

7,898

 

45,060

 

0.18

 

2,518

 

7,050

 

0.36

 

Total

 

$

26,564

 

109,195

 

0.24

 

$

47,349

 

65,689

 

0.72

 

 

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

 

Our water solutions segment generated $10.7 million of water transportation revenue during the six months ended September 30, 2014. These revenues related to our water transportation business, which we sold during September 2014.

 

Cost of Sales . We enter into derivatives in our water solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expected to recover when processing the wastewater. Our cost of sales during the six months ended September 30, 2015 was reduced by $2.5 million of net unrealized gains on derivatives and $2.5 million of net realized gains on derivatives. Our cost of sales during the six months ended September 30, 2014 was reduced by $6.6 million of net unrealized gains on derivatives and increased by $1.5 million of net realized losses on derivatives.

 

Our other cost of sales was $6.2 million during the six months ended September 30, 2014. These costs related primarily to our water transportation business, which we sold during September 2014.

 

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

 

 

 

Six Months Ended September 30,

 

 

 

 

 

2015

 

2014

 

Change

 

 

 

(in thousands)

 

Existing facilities

 

$

37,683

 

$

43,611

 

$

(5,928

)

Recently developed facilities

 

4,925

 

 

4,925

 

Recently acquired facilities

 

22,341

 

5,137

 

17,204

 

Total

 

$

64,949

 

$

48,748

 

$

16,201

 

 

The decrease in operating expenses for existing facilities was due primarily to a loss of $4.0 million related to the sale of our water transportation business during September 2014, and to lower operating costs of water disposal wells at existing facilities due to lower volumes processed.

 

General and Administrative Expenses . Our water solutions segment incurred general and administrative expenses of $1.4 million during the six months ended September 30, 2015, compared to $1.6 million during the six months ended September 30, 2014.

 

Depreciation and Amortization Expense . Our water solutions segment incurred depreciation and amortization expense of $43.3 million during the six months ended September 30, 2015, compared to $34.7 million during the six months ended September 30, 2014. Of this increase, $7.1 million related to recently acquired facilities and $1.2 million related to recently developed facilities.

 

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Table of Contents

 

Liquids

 

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

 

 

 

Six Months Ended September 30,

 

 

 

 

 

2015

 

2014 (1)

 

Change

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Propane sales

 

$

204,260

 

$

463,736

 

$

(259,476

)

Other product sales

 

308,347

 

595,075

 

(286,728

)

Other revenues

 

19,622

 

11,582

 

8,040

 

Total revenues (2)

 

532,229

 

1,070,393

 

(538,164

)

Expenses:

 

 

 

 

 

 

 

Cost of sales—propane

 

205,273

 

454,638

 

(249,365

)

Cost of sales—other products

 

265,347

 

568,640

 

(303,293

)

Cost of sales—other

 

7,023

 

8,285

 

(1,262

)

Operating expenses

 

22,301

 

18,248

 

4,053

 

General and administrative expenses

 

4,637

 

3,981

 

656

 

Depreciation and amortization expense

 

7,749

 

6,585

 

1,164

 

Total expenses

 

512,330

 

1,060,377

 

(548,047

)

Segment operating income

 

$

19,899

 

$

10,016

 

$

9,883

 

 


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

 

(2)          Revenues include $24.3 million and $55.5 million of intersegment sales during the six months ended September 30, 2015 and 2014, respectively, that are eliminated in our condensed consolidated statements of operations.

 

Revenues . Our liquids segment generated $204.3 million of wholesale propane sales revenue during the six months ended September 30, 2015, selling 471.6 million gallons at an average price of $0.43 per gallon. During the six months ended September 30, 2014, our liquids segment generated $463.7 million of wholesale propane sales revenue, selling 424.0 million gallons at an average price of $1.09 per gallon. The increase in the volume sold was due primarily to the expansion of an agreement under which we market the majority of the production from a fractionation facility.

 

Our liquids segment generated $308.3 million of other wholesale products sales revenue during the six months ended September 30, 2015, selling 424.2 million gallons at an average price of $0.73 per gallon. During the six months ended September 30, 2014, our liquids segment generated $595.1 million of other wholesale products sales revenue, selling 384.2 million gallons at an average price of $1.55 per gallon. The increase in the volume of other wholesale products sold was due to expanded operations.

 

Our liquids segment generated $19.6 million of other revenues during the six months ended September 30, 2015, compared to $11.6 million during the six months ended September 30, 2014. This revenue includes storage income and income generated from the operation of a terminal for a customer. This increase was due primarily to $10.0 million of revenue related to Sawtooth, which we acquired in February 2015.

 

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Cost of Sales . Our cost of wholesale propane sales was $205.3 million during the six months ended September 30, 2015, as we sold 471.6 million gallons at an average cost of $0.44 per gallon. Our cost of wholesale propane sales during the six months ended September 30, 2015 was increased by $0.9 million of net unrealized losses on derivatives. During the six months ended September 30, 2014, our cost of wholesale propane sales was $454.6 million, as we sold 424.0 million gallons at an average cost of $1.07 per gallon. Our cost of wholesale propane sales during the six months ended September 30, 2014 was increased by $1.7 million of net unrealized losses on derivatives. The following table summarizes our product margins for propane sales (in thousands, except per gallon amounts) for the periods indicated:

 

 

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Propane revenues

 

$

204,260

 

$

463,736

 

Propane cost of sales

 

(205,273

)

(454,638

)

Propane product margin (loss)

 

$

(1,013

)

$

9,098

 

 

 

 

 

 

 

Propane sold (gallons)

 

471,615

 

423,992

 

 

 

 

 

 

 

Product margin (loss) per gallon

 

$

(0.002

)

$

0.021

 

 

Propane prices declined during the six months ended September 30, 2015, which had an adverse impact on product margins.

 

Our cost of sales of other products was $265.3 million during the six months ended September 30, 2015, as we sold 424.2 million gallons at an average cost of $0.63 per gallon. Our cost of sales of other products during the six months ended September 30, 2015 was reduced by $1.6 million of net unrealized gains on derivatives. During the six months ended September 30, 2014, our cost of sales of other products was $568.6 million, as we sold 384.2 million gallons at an average cost of $1.48 per gallon. Our cost of sales of other products during the six months ended September 30, 2014 was reduced by $0.8 million of net unrealized gains on derivatives. The following table summarizes our per gallon product margins (in thousands, except per gallon amounts) for the periods indicated:

 

 

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Other products revenues

 

$

308,347

 

$

595,075

 

Other products cost of sales

 

(265,347

)

(568,640

)

Other products product margin

 

$

43,000

 

$

26,435

 

 

 

 

 

 

 

Other products sold (gallons)

 

424,214

 

384,235

 

 

 

 

 

 

 

Product margin per gallon

 

$

0.101

 

$

0.069

 

 

Product margins during the six months ended September 30, 2015 benefitted from a high level of butane supply in the market, which lowered our product cost.

 

Operating Expenses . Our liquids segment incurred operating expenses of $22.3 million during the six months ended September 30, 2015, compared to $18.2 million during the six months ended September 30, 2014. The increase in operating expenses was due primarily to $2.3 million of expenses related to Sawtooth, which we acquired in February 2015, and to increased compensation expense.

 

General and Administrative Expenses . Our liquids segment incurred general and administrative expenses of $4.6 million during the six months ended September 30, 2015, compared to $4.0 million during the six months ended September 30, 2014. The increase in general and administrative expenses was due primarily to $0.7 million of expenses related to Sawtooth, which we acquired in February 2015.

 

Depreciation and Amortization Expense . Our liquids segment incurred depreciation and amortization expense of $7.7 million during the six months ended September 30, 2015, compared to $6.6 million during the six months ended September 30, 2014. The increase in depreciation and amortization expense was due to $2.7 million of expense during the six months ended September 30, 2015 related to Sawtooth, which we acquired in February 2015. This increase was partially offset by $0.9 million of depreciation expense we recorded during the six months ended September 30, 2014 related to a natural gas liquids terminal that we sold in December 2014.

 

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Table of Contents

 

Retail Propane

 

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

 

 

 

Six Months Ended September 30,

 

 

 

 

 

2015

 

2014

 

Change

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Propane sales

 

$

79,304

 

$

100,578

 

$

(21,274

)

Distillate sales

 

20,625

 

30,225

 

(9,600

)

Other revenues

 

17,724

 

15,457

 

2,267

 

Total revenues

 

117,653

 

146,260

 

(28,607

)

Expenses:

 

 

 

 

 

 

 

Cost of sales—propane

 

28,232

 

56,721

 

(28,489

)

Cost of sales—distillates

 

15,975

 

25,876

 

(9,901

)

Cost of sales—other

 

6,236

 

4,821

 

1,415

 

Operating expenses

 

46,256

 

42,687

 

3,569

 

General and administrative expenses

 

5,804

 

5,548

 

256

 

Depreciation and amortization expense

 

17,615

 

15,255

 

2,360

 

Total expenses

 

120,118

 

150,908

 

(30,790

)

Segment operating loss

 

$

(2,465

)

$

(4,648

)

$

2,183

 

 

Revenues . Our retail propane segment generated revenue of $79.3 million from propane sales during the six months ended September 30, 2015, selling 47.5 million gallons at an average price of $1.67 per gallon. During the six months ended September 30, 2014, our retail propane segment generated $100.6 million of revenue from propane sales, selling 47.1 million gallons at an average price of $2.13 per gallon.

 

Our retail propane segment generated revenue of $20.6 million from distillate sales during the six months ended September 30, 2015, selling 8.6 million gallons at an average price of $2.39 per gallon. During the six months ended September 30, 2014, our retail propane segment generated $30.2 million of revenue from distillate sales, selling 8.7 million gallons at an average price of $3.47 per gallon.

 

Cost of Sales . Our cost of retail propane sales was $28.2 million during the six months ended September 30, 2015, as we sold 47.5 million gallons at an average cost of $0.59 per gallon. During the six months ended September 30, 2014, our cost of retail propane sales was $56.7 million, as we sold 47.1 million gallons at an average cost of $1.20 per gallon. The following table summarizes our product margins for retail propane sales (in thousands, except per gallon amounts) for the periods indicated:

 

 

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Propane revenues

 

$

79,304

 

$

100,578

 

Propane cost of sales

 

(28,232

)

(56,721

)

Propane product margin

 

$

51,072

 

$

43,857

 

 

 

 

 

 

 

Propane sold (gallons)

 

47,502

 

47,142

 

 

 

 

 

 

 

Product margin per gallon

 

$

1.08

 

$

0.93

 

 

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Our cost of distillate sales was $16.0 million during the six months ended September 30, 2015, as we sold 8.6 million gallons at an average cost of $1.85 per gallon. During the six months ended September 30, 2014, our cost of distillate sales was $25.9 million, as we sold 8.7 million gallons at an average cost of $2.97 per gallon. The following table summarizes our product margins for distillate sales (in thousands, except per gallon amounts) for the periods indicated:

 

 

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Distillate revenues

 

$

20,625

 

$

30,225

 

Distillate cost of sales

 

(15,975

)

(25,876

)

Distillate product margin

 

$

4,650

 

$

4,349

 

 

 

 

 

 

 

Distillate sold (gallons)

 

8,643

 

8,712

 

 

 

 

 

 

 

Product margin per gallon

 

$

0.54

 

$

0.50

 

 

Operating Expenses . Our retail propane segment incurred operating expenses of $46.3 million during the six months ended September 30, 2015, compared to $42.7 million during the six months ended September 30, 2014. The increase in operating expenses was due primarily to increased employee compensation expense in support of the growth of our business.

 

General and Administrative Expenses . Our retail propane segment incurred general and administrative expenses of $5.8 million during the six months ended September 30, 2015, compared to $5.5 million during the six months ended September 30, 2014.

 

Depreciation and Amortization Expense . Our retail propane segment incurred depreciation and amortization expense of $17.6 million during the six months ended September 30, 2015, compared to $15.3 million during the six months ended September 30, 2014.

 

Refined Products and Renewables

 

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

 

 

 

Six Months Ended September 30,

 

 

 

 

 

2015

 

2014 (1)

 

Change

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Refined products sales (2)

 

$

3,413,208

 

$

3,452,612

 

$

(39,404

)

Renewables sales

 

199,342

 

248,099

 

(48,757

)

Service fees

 

56,812

 

24,006

 

32,806

 

Total revenues

 

3,669,362

 

3,724,717

 

(55,355

)

Expenses:

 

 

 

 

 

 

 

Cost of sales—refined products

 

3,356,161

 

3,419,480

 

(63,319

)

Cost of sales—renewables

 

199,095

 

245,684

 

(46,589

)

Operating expenses

 

51,401

 

31,462

 

19,939

 

General and administrative expenses

 

9,602

 

7,763

 

1,839

 

Depreciation and amortization expense

 

25,327

 

12,761

 

12,566

 

Total expenses

 

3,641,586

 

3,717,150

 

(75,564

)

Segment operating income

 

$

27,776

 

$

7,567

 

$

20,209

 

 


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

 

(2)          Revenues include $0.5 million of intersegment sales during the six months ended September 30, 2015 that are eliminated in our condensed consolidated statement of operations.

 

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Revenues . Our refined products sales revenue was $3.4 billion during the six months ended September 30, 2015, selling 45.1 million barrels at an average price of $75.72 per barrel. Our refined products sales revenue was $3.5 billion during the six months ended September 30, 2014, selling 29.1 million barrels at an average price of $118.67 per barrel.

 

Our renewables sales revenue was $199.3 million during the six months ended September 30, 2015, selling 2.7 million barrels at an average price of $74.30 per barrel. Our renewables sales revenue was $248.1 million during the six months ended September 30, 2014, selling 2.5 million barrels at an average price of $99.64 per barrel.

 

Our refined products and renewables segment generated $56.8 million of service fee revenues during the six months ended September 30, 2015, compared to $24.0 million during the six months ended September 30, 2014.

 

Cost of Sales . Our cost of refined products sales was $3.4 billion during the six months ended September 30, 2015, as we sold 45.1 million barrels at an average cost of $74.46 per barrel. Our cost of refined products sales was $3.4 billion during the six months ended September 30, 2014, as we sold 29.1 million barrels at an average cost of $117.53 per barrel. The following table summarizes our refined product margins (in thousands, except per barrel and per gallon amounts) for the periods indicated:

 

 

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Refined products revenues

 

$

3,413,208

 

$

3,452,612

 

Refined products cost of sales

 

(3,356,161

)

(3,419,480

)

Refined products product margin

 

$

57,047

 

$

33,132

 

 

 

 

 

 

 

Refined products sold (barrels)

 

45,075

 

29,094

 

 

 

 

 

 

 

Product margin per barrel

 

$

1.266

 

$

1.139

 

Product margin per gallon

 

$

0.030

 

$

0.027

 

 

Per-barrel product margins were higher during the six months ended September 30, 2015 than during the six months ended September 30, 2014, due primarily to the inclusion of TransMontaigne in the full six months of the current fiscal year. Per-barrel product margins are typically higher for TransMontaigne’s operations than they are for the refined product operations we owned prior to the acquisition of TransMontaigne.

 

Our cost of renewables sales was $199.1 million during the six months ended September 30, 2015, as we sold 2.7 million barrels at an average cost of $74.21 per barrel. Our cost of renewables sales was $245.7 million during the six months ended September 30, 2014, as we sold 2.5 million barrels at an average cost of $98.67 per barrel. The following table summarizes our renewables product margins (in thousands, except per barrel and per gallon amounts) for the periods indicated:

 

 

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Renewables revenues

 

$

199,342

 

$

248,099

 

Renewables cost of sales

 

(199,095

)

(245,684

)

Renewables product margin

 

$

247

 

$

2,415

 

 

 

 

 

 

 

Renewable products sold (barrels)

 

2,683

 

2,490

 

 

 

 

 

 

 

Product margin per barrel

 

$

0.092

 

$

0.970

 

Product margin per gallon

 

$

0.002

 

$

0.023

 

 

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Per-barrel product margins were lower during the six months ended September 30, 2015 than during the six months ended September 30, 2014 due primarily to lower renewables prices caused by increased import activity.

 

Operating Expenses . Our refined products and renewables segment incurred operating expenses of $51.4 million during the six months ended September 30, 2015, compared to $31.5 million during the six months ended September 30, 2014. This increase was due primarily to the inclusion of TransMontaigne in the full six months of the current fiscal year, compared to three months of the prior fiscal year.

 

General and Administrative Expenses. Our refined products and renewables segment incurred general and administrative expenses of $9.6 million during the six months ended September 30, 2015, compared to $7.8 million during the six months ended September 30, 2014. This increase was due primarily to the inclusion of TransMontaigne in the full six months of the current fiscal year, compared to three months of the prior fiscal year. General and administrative expenses during the six months ended September 30, 2014 were increased by $1.5 million of compensation expense related to termination benefits for certain TransMontaigne employees.

 

Depreciation and Amortization Expense . Our refined products and renewables segment incurred depreciation and amortization expense of $25.3 million during the six months ended September 30, 2015, compared to $12.8 million during the six months ended September 30, 2014. This increase was due primarily to depreciation on TLP’s terminal assets and amortization of customer relationship intangible assets acquired in the business combination with TransMontaigne. Of the depreciation and amortization expense, TLP’s depreciation and amortization expense was $23.5 million and $10.3 million during the six months ended September 30, 2015 and 2014, respectively.

 

Corporate and Other

 

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

 

 

 

Six Months Ended September 30,

 

 

 

 

 

2015

 

2014

 

Change

 

 

 

(in thousands)

 

Incentive compensation expense

 

$

(51,292

)

$

(22,210

)

$

(29,082

)

Acquisition expenses

 

(631

)

(4,328

)

3,697

 

Other corporate expenses

 

(16,788

)

(14,568

)

(2,220

)

Total

 

$

(68,711

)

$

(41,106

)

$

(27,605

)

 

The expenses shown in the table above for incentive compensation include cash-based and equity-based compensation. Such incentive compensation expenses were higher during the six months ended September 30, 2015 than during the six months ended September 30, 2014, due primarily to two factors described below.

 

As part of its review of our executive compensation program, the Compensation Committee of the Board of Directors approved a new type of equity-based compensation award, under which the number of units that vest is contingent upon the performance of our common units relative to the performance of other entities in the Alerian MLP Index. During the six months ended September 30, 2015, three tranches of these Performance Awards were granted, with vesting dates of July 1, 2015, July 1, 2016, and July 1, 2017, respectively. We recorded $18.1 million of expense related to the Performance Awards during the six months ended September 30, 2015, $16.1 million of which related to awards that vested on July 1, 2015.

 

We have also granted certain Service Awards, which vest contingent only on the continued service of the recipients. The number of outstanding Service Awards was higher at September 30, 2015 than at September 30, 2014. This was due in part to the addition of new employees as our business has expanded, and was due in part to increases in the number of Service Awards granted to certain employees following the Compensation Committee’s review of our compensation program. The expense associated with these Service Awards (exclusive of accruals of annual bonuses paid or expected to be paid in common units) was $21.6 million during the six months ended September 30, 2015, compared to $11.2 million during the six months ended September 30, 2014.

 

The expense associated with annual bonuses (a portion of which were paid or are expected to be paid in common units) was $11.6 million during the six months ended September 30, 2015, compared to $11.0 million during the six months ended September 30, 2014.

 

The expenses shown in the table above for acquisitions relate primarily to legal and advisory costs. We incurred $3.7 million of such expenses during the six months ended September 30, 2014 related to our acquisition of TransMontaigne.

 

The increase in other corporate expenses was due to the continued growth of our business.

 

Equity in Earnings of Unconsolidated Entities

 

Equity in earnings of unconsolidated entities was $2.4 million during the three months ended September 30, 2015, compared to $3.7 million during the three months ended September 30, 2014. The decrease was due primarily to a decrease of $2.0 million in earnings

 

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from our investments in Glass Mountain and an ethanol production facility, partially offset by an increase of $1.1 million in earnings from our investments in BOSTCO and Frontera.

 

Equity in earnings of unconsolidated entities was $11.2 million during the six months ended September 30, 2015, compared to $6.3 million during the six months ended September 30, 2014. The increase was due primarily to $6.9 million of earnings from BOSTCO and Frontera that we acquired as part of our July 2014 acquisition of TransMontaigne, partially offset by a decrease of $1.8 million in earnings from our investments in Glass Mountain and an ethanol production facility.

 

Interest Expense

 

Interest expense includes interest expense on our revolving credit facilities and senior notes, amortization of debt issuance costs, letter of credit fees, interest on equipment financing notes, and accretion of interest on noninterest bearing debt obligations. Interest expense was $31.6 million during the three months ended September 30, 2015, compared to $28.7 million during the three months ended September 30, 2014. The increase in interest expense was due primarily to the increased level of debt outstanding on our Revolving Credit Facility (hereinafter defined) (the average balance outstanding on our Revolving Credit Facility was $1.6 billion during the three months ended September 30, 2015, compared to $1.0 billion during three months ended September 30, 2014), primarily to finance acquisitions and capital expenditures.

 

Interest expense was $62.4 million during the six months ended September 30, 2015, compared to $49.1 million during the six months ended September 30, 2014. The increase in interest expense was due primarily to the increased level of debt outstanding on our Revolving Credit Facility (the average balance outstanding on our Revolving Credit Facility was $1.6 billion during the six months ended September 30, 2015, compared to $1.0 billion during six months ended September 30, 2014), primarily to finance acquisitions and capital expenditures. The increase in interest expense was also due in part to the fact that we issued $400.0 million of fixed-rate notes during July 2014, and the interest rate on these notes has been higher than the interest rate on the Revolving Credit Facility. The increase in interest expense was also due in part to increased interest expense associated with TLP’s credit facility. This increase was due primarily to the fact that we did not acquire our ownership interest in TLP until July 2014.

 

Other Income (Expense), Net

 

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

 

 

 

Three Months Ended September 30,

 

Six Months Ended September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

(in thousands)

 

Interest income

 

$

2,823

 

$

633

 

$

6,700

 

$

1,224

 

Crude oil marketing arrangement

 

(1,887

)

(1,692

)

(5,835

)

(3,747

)

Other

 

1,019

 

442

 

(85

)

1,515

 

Other income (expense), net

 

$

1,955

 

$

(617

)

$

780

 

$

(1,008

)

 

Interest income relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility being used by a third party and a loan receivable from an equity method investee. Amounts reflected in the table above for crude oil marketing agreement relate to another party’s share of the profits generated from a joint marketing arrangement.

 

Income Tax Provision (Benefit)

 

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

 

We have certain taxable corporate subsidiaries in the United States and in Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales. Our fiscal years 2012 to 2015 generally remain subject to examination by federal, state, and Canadian tax authorities. We use the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between

 

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the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.

 

Income tax benefit was $2.8 million during the three months ended September 30, 2015, compared to $1.9 million during the three months ended September 30, 2014. TransMontaigne was a taxable subsidiary from July 1, 2014 (the date we acquired TransMontaigne) to December 30, 2014 (the date we converted TransMontaigne to a non-taxable entity). Income tax benefit during the three months ended September 30, 2015 includes a benefit of $3.6 million related to a change in estimate of the income tax obligation payable related to TransMontaigne.

 

Income tax benefit was $2.2 million during the six months ended September 30, 2015, compared to $0.9 million during the six months ended September 30, 2014. TransMontaigne was a taxable subsidiary from July 1, 2014 (the date we acquired TransMontaigne) to December 30, 2014 (the date we converted TransMontaigne to a non-taxable entity). Income tax benefit during the six months ended September 30, 2015 includes a benefit of $3.6 million related to a change in estimate of the income tax obligation payable related to TransMontaigne.

 

Noncontrolling Interests

 

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

 

Net income attributable to noncontrolling interests was $2.9 million during the three months ended September 30, 2015, compared to $3.3 million during the three months ended September 30, 2014.

 

Net income attributable to noncontrolling interests was $6.8 million during the six months ended September 30, 2015, compared to $3.4 million during the six months ended September 30, 2014. The increase was due primarily to the July 2014 acquisition of TransMontaigne, in which we acquired a 19.7% limited partner interest in TLP.

 

Seasonality

 

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

 

Liquidity, Sources of Capital and Capital Resource Activities

 

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

 

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

 

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

 

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

 

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We continue to pursue a strategy of growth through acquisitions. We expect to consider financing future acquisitions through a variety of sources, including the use of available capacity on our Revolving Credit Facility, the issuance of common units to sellers of businesses we acquire, private placements of debt or equity securities, and public offerings of debt or equity securities. Our ability to raise additional capital through the issuance of debt or equity securities will have a significant impact on our ability to continue to pursue our growth strategy.

 

Credit Agreement

 

We have entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). At September 30, 2015, our Revolving Credit Facility had a total capacity of $2.296 billion.

 

The Expansion Capital Facility had a total capacity of $1.258 billion for cash borrowings at September 30, 2015. At that date, we had outstanding borrowings of $1.083 billion on the Expansion Capital Facility. The Working Capital Facility had a total capacity of $1.038 billion for cash borrowings and letters of credit at September 30, 2015. At that date, we had outstanding borrowings of $656.0 million and outstanding letters of credit of $89.6 million on the Working Capital Facility. Amounts outstanding for letters of credit are not recorded as long-term debt on our condensed consolidated balance sheets, although they decrease our borrowing capacity under the Working Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base,” as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time. During October 2015, we entered into an agreement with the lenders to increase the total capacity on the Expansion Capital Facility by $150 million, as allowed for under an “accordion” feature in the Credit Agreement.

 

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

 

All borrowings under the Credit Agreement bear interest, at our option, at either (i) an alternate base rate plus a margin of 0.50% to 1.50% per year or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per year. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At September 30, 2015, the borrowings under the Credit Agreement were LIBOR borrowings with an interest rate at September 30, 2015 of 2.21%, calculated as the LIBOR rate of 0.21% plus a margin of 2.0%. At September 30, 2015, the interest rate in effect on letters of credit was 2.25%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused capacity.

 

The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our leverage ratio, as defined in the Credit Agreement, cannot exceed 4.25 to 1 at any quarter end. The leverage coverage ratio in our Credit Agreement excludes TLP’s debt. At September 30, 2015, our leverage ratio was approximately 3.5 to 1. The Credit Agreement also specifies that our interest coverage ratio, as defined in the Credit Agreement, cannot be less than 2.75 to 1 at any quarter end. At September 30, 2015, our interest coverage ratio was approximately 5.9 to 1.

 

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

 

At September 30, 2015, we were in compliance with the covenants under the Credit Agreement.

 

2019 Notes

 

On July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the “2019 Notes”). The 2019 Notes mature on July 15, 2019. Interest is payable on January 15 and July 15 of each year. We have the right to redeem the 2019 Notes before the maturity date, although we would be required to pay a premium for early redemption.

 

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2019 Notes, and the obligations under the 2019 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The indenture governing the 2019 Notes contains various customary

 

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

 

At September 30, 2015, we were in compliance with the covenants under the indenture governing the 2019 Notes.

 

2021 Notes

 

On October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the “2021 Notes”). The 2021 Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the 2021 Notes before the maturity date, although we would be required to pay a premium for early redemption.

 

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2021 Notes, and the obligations under the 2021 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The indenture governing the 2021 Notes contains various customary covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

 

At September 30, 2015, we were in compliance with the covenants under the indenture governing the 2021 Notes.

 

2022 Notes

 

On June 19, 2012, we entered into a Note Purchase Agreement (as amended, the “Note Purchase Agreement”) whereby we issued $250.0 million of Senior Notes in a private placement (the “2022 Notes”). The 2022 Notes bear interest at a fixed rate of 6.65%, which is payable quarterly. The 2022 Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to prepay outstanding principal, although we would incur a prepayment penalty. The 2022 Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

 

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

 

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

 

At September 30, 2015, we were in compliance with the covenants under the Note Purchase Agreement.

 

TLP Credit Facility

 

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

 

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net tangible assets,” and additional future “permitted JV investments” up to $125 million, which may include additional investments in BOSTCO. The commitments under the TLP Credit Facility mature on July 31, 2018.

 

TLP may elect to have loans under the TLP Credit Facility bear interest at either (i) a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLP also pays commitment fees on any unused capacity, ranging from 0.375% to 0.5% per year, depending on the total leverage ratio then in effect. For the three months ended September 30, 2015, the weighted-average interest rate on borrowings under the TLP Credit Facility was approximately 2.6%. TLP’s obligations under the TLP Credit Facility are secured by a first priority security interest in favor of the lenders in the majority of TLP’s assets, including TLP’s investments in unconsolidated entities. At September 30, 2015, TLP had outstanding borrowings under the TLP Credit Facility of $249.6 million and no outstanding letters of credit.

 

The TLP Credit Facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the TLP Credit Facility are (i) a total leverage ratio test (not to exceed 4.75 times), (ii) a senior secured leverage ratio test (not to exceed 3.75 times) if TLP issues senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times). These financial covenants are based on “Consolidated EBITDA” as defined in the TLP Credit Facility. The TLP Credit Facility is non-recourse to the Partnership. At September 30, 2015, TLP was in compliance with the covenants under the TLP Credit Facility.

 

The following table summarizes our basis in the assets and liabilities of TLP at September 30, 2015, inclusive of the impact of our acquisition accounting for the business combination with TransMontaigne (in thousands):

 

Cash and cash equivalents

 

$

791

 

Accounts receivable—trade

 

3,074

 

Accounts receivable—affiliates

 

679

 

Inventories

 

1,250

 

Prepaid expenses and other current assets

 

858

 

Property, plant and equipment, net

 

477,357

 

Goodwill

 

30,169

 

Intangible assets, net

 

61,696

 

Investments in unconsolidated entities

 

255,757

 

Other noncurrent assets

 

968

 

Accounts payable—trade

 

(6,760

)

Accounts payable—affiliates

 

(121

)

Net intercompany payable

 

(1,911

)

Accrued expenses and other payables

 

(7,054

)

Advanced payments received from customers

 

(151

)

Long-term debt

 

(249,600

)

Other noncurrent liabilities

 

(3,441

)

Net assets

 

$

563,561

 

 

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Revolving Credit Balances

 

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

 

 

 

Average

 

 

 

 

 

 

 

Daily

 

Lowest

 

Highest

 

 

 

Outstanding

 

Balance

 

Balance

 

 

 

(in thousands)

 

Six Months Ended September 30, 2015

 

 

 

 

 

 

 

Expansion capital borrowings

 

$

893,002

 

$

739,500

 

$

1,083,000

 

Working capital borrowings

 

672,921

 

582,500

 

756,000

 

TLP credit facility borrowings

 

253,247

 

245,000

 

263,400

 

 

 

 

 

 

 

 

 

Six Months Ended September 30, 2014

 

 

 

 

 

 

 

Expansion capital borrowings

 

$

346,855

 

$

114,000

 

$

578,500

 

Working capital borrowings

 

640,369

 

339,500

 

1,024,500

 

TLP credit facility borrowings

 

246,750

 

228,000

 

258,500

 

 

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)

 

2015

 

2014

 

 

 

(in thousands)

 

Operating activities, before changes in operating assets and liabilities

 

$

74,014

 

$

19,091

 

Changes in operating assets and liabilities

 

100,081

 

(80,726

)

 

 

 

 

 

 

Operating activities

 

$

174,095

 

$

(61,635

)

 

 

 

 

 

 

Investing activities

 

(340,930

)

(750,288

)

 

 

 

 

 

 

Financing activities

 

155,585

 

813,306

 

 

Operating Activities. The seasonality of our natural gas liquids businesses has a significant effect on our cash flows from operating activities. Increases in natural gas liquids prices typically reduce our operating cash flows due to higher cash requirements to fund increases in inventories, and decreases in natural gas liquids prices typically increase our operating cash flows due to lower cash requirements to fund increases in inventories.

 

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

 

Investing Activities . Net cash used in investing activities was $340.9 million during the six months ended September 30, 2015, compared to $750.3 million during the six months ended September 30, 2014. The decrease in net cash used in investing activities was due primarily to:

 

·                   a $508.2 million decrease in cash paid for acquisitions during the six months ended September 30, 2015 due primarily to the July 2014 acquisition of TransMontaigne; and

 

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·                   a $38.7 million increase in cash flows from derivatives.

 

These decreases were partially offset by an increase in capital expenditures from $82.9 million during the six months ended September 30, 2014, $65.7 million of which was expansion capital and $17.2 million of which was maintenance capital (of this maintenance capital, $0.1 million related to TLP), to $222.3 million during the six months ended September 30, 2015, $196.3 million of which was expansion capital and $26.0 million of which was maintenance capital (of this maintenance capital, $7.1 million related to TLP).

 

Financing Activities . Net cash provided by financing activities was $155.6 million during the six months ended September 30, 2015, compared to $813.3 million during the six months ended September 30, 2014. The decrease in net cash provided by financing activities was due primarily to:

 

·                   $400.0 million in proceeds received from the issuance of the 2019 Notes during the six months ended September 30, 2014;

 

·                   $370.4 million in proceeds received from the sale of our common units during the six months ended September 30, 2014; and

 

·                   a $52.9 million increase in distributions paid to our partners and noncontrolling interest owners during the six months ended September 30, 2015.

 

These decreases were partially offset by a $172.6 million increase in borrowings on our revolving credit facilities (net of repayments) during the six months ended September 30, 2015.

 

The following table summarizes the distributions declared after our initial public offering:

 

 

 

 

 

 

 

Amount

 

Amount Paid To

 

Amount Paid To

 

Date Declared

 

Record Date

 

Date Paid

 

Per Unit

 

Limited Partners

 

General Partner

 

 

 

 

 

 

 

 

 

(in thousands)

 

(in thousands)

 

July 25, 2011

 

August 3, 2011

 

August 12, 2011

 

$

0.1669

 

$

2,467

 

$

3

 

October 21, 2011

 

October 31, 2011

 

November 14, 2011

 

0.3375

 

4,990

 

5

 

January 24, 2012

 

February 3, 2012

 

February 14, 2012

 

0.3500

 

7,735

 

10

 

April 19, 2012

 

April 30, 2012

 

May 15, 2012

 

0.3625

 

9,165

 

10

 

July 24, 2012

 

August 3, 2012

 

August 14, 2012

 

0.4125

 

13,574

 

134

 

October 17, 2012

 

October 29, 2012

 

November 14, 2012

 

0.4500

 

22,846

 

707

 

January 24, 2013

 

February 4, 2013

 

February 14, 2013

 

0.4625

 

24,245

 

927

 

April 25, 2013

 

May 6, 2013

 

May 15, 2013

 

0.4775

 

25,605

 

1,189

 

July 25, 2013

 

August 5, 2013

 

August 14, 2013

 

0.4938

 

31,725

 

1,739

 

October 23, 2013

 

November 4, 2013

 

November 14, 2013

 

0.5113

 

35,908

 

2,491

 

January 24, 2014

 

February 4, 2014

 

February 14, 2014

 

0.5313

 

42,150

 

4,283

 

April 24, 2014

 

May 5, 2014

 

May 15, 2014

 

0.5513

 

43,737

 

5,754

 

July 24, 2014

 

August 4, 2014

 

August 14, 2014

 

0.5888

 

52,036

 

9,481

 

October 24, 2014

 

November 4, 2014

 

November 14, 2014

 

0.6088

 

53,902

 

11,141

 

January 26, 2015

 

February 6, 2015

 

February 13, 2015

 

0.6175

 

54,684

 

11,860

 

April 24, 2015

 

May 5, 2015

 

May 15, 2015

 

0.6250

 

59,651

 

13,446

 

July 23, 2015

 

August 3, 2015

 

August 14, 2015

 

0.6325

 

66,244

 

15,483

 

October 22, 2015

 

November 3, 2015

 

November 13, 2015

 

0.6400

 

67,305

 

16,277

 

 

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

 

 

 

 

 

 

 

Amount

 

Amount Paid

 

Amount Paid To

 

Date Declared

 

Record Date

 

Date Paid

 

Per Unit

 

To NGL

 

Other Partners

 

 

 

 

 

 

 

 

 

(in thousands)

 

(in thousands)

 

October 13, 2014

 

October 31, 2014

 

November 7, 2014

 

$

0.6650

 

$

4,010

 

$

8,614

 

January 8, 2015

 

January 30, 2015

 

February 6, 2015

 

0.6650

 

4,010

 

8,614

 

April 13, 2015

 

April 30, 2015

 

May 7, 2015

 

0.6650

 

4,007

 

8,617

 

July 13, 2015

 

July 31, 2015

 

August 7, 2015

 

0.6650

 

4,007

 

8,617

 

October 12, 2015

 

October 30, 2015

 

November 6, 2015

 

0.6650

 

4,007

 

8,617

 

 

Unit Repurchase Program

 

On September 10, 2015, the Board of Directors of our general partner authorized a unit repurchase program, under which we may repurchase up to $45 million of our outstanding common units through March 31, 2016. We may repurchase units from time to time in the open market or in other privately negotiated transactions. The unit repurchase program authorization does not obligate us to repurchase any dollar amount or number of our units. During September 2015, we repurchased 157,626 common units for an aggregate price of $3.7 million.

 

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Contractual Obligations

 

The following table summarizes our contractual obligations at September 30, 2015 for our fiscal years ending thereafter:

 

 

 

 

 

Six Months

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ending

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

Year Ending March 31,

 

 

 

 

 

Total

 

2016

 

2017

 

2018

 

2019

 

2020

 

Thereafter

 

 

 

(in thousands)

 

Principal payments on long-term debt—

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Expansion capital borrowings

 

$

1,083,000

 

$

 

$

 

$

 

$

1,083,000

 

$

 

$

 

Working capital borrowings

 

656,000

 

 

 

 

656,000

 

 

 

2019 Notes

 

400,000

 

 

 

 

 

400,000

 

 

2021 Notes

 

450,000

 

 

 

 

 

 

450,000

 

2022 Notes

 

250,000

 

 

 

25,000

 

50,000

 

50,000

 

125,000

 

TLP Credit Facility

 

249,600

 

 

 

 

249,600

 

 

 

Other long-term debt

 

9,134

 

1,891

 

2,879

 

2,129

 

1,413

 

344

 

478

 

Interest payments on long-term debt—

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revolving Credit Facility (1)

 

130,690

 

21,079

 

42,158

 

42,158

 

25,295

 

 

 

2019 Notes

 

82,000

 

10,250

 

20,500

 

20,500

 

20,500

 

10,250

 

 

2021 Notes

 

201,094

 

15,469

 

30,938

 

30,938

 

30,938

 

30,938

 

61,873

 

2022 Notes

 

74,812

 

8,313

 

16,625

 

16,209

 

13,300

 

9,975

 

10,390

 

TLP Credit Facility

 

19,242

 

3,395

 

6,789

 

6,789

 

2,269

 

 

 

Other long-term debt

 

783

 

165

 

274

 

177

 

94

 

53

 

20

 

Letters of credit

 

89,647

 

 

 

 

89,647

 

 

 

Future minimum lease payments under noncancelable operating leases

 

503,436

 

60,441

 

106,125

 

90,783

 

66,385

 

56,509

 

123,193

 

Future minimum throughput payments under noncancelable agreements (2)

 

477,963

 

56,753

 

85,349

 

85,435

 

84,643

 

74,811

 

90,972

 

Construction commitments (3)

 

584,560

 

247,593

 

336,967

 

 

 

 

 

Fixed-price commodity purchase commitments (4)

 

38,651

 

37,706

 

945

 

 

 

 

 

Index-price commodity purchase commitments (5)

 

600,941

 

567,806

 

33,135

 

 

 

 

 

Total contractual obligations

 

$

5,901,553

 

$

1,030,861

 

$

682,684

 

$

320,118

 

$

2,373,084

 

$

632,880

 

$

861,926

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchase commitments (thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas liquids fixed-price (gallons) (6)

 

61,618

 

59,854

 

1,764

 

 

 

 

 

Natural gas liquids index-price (gallons) (6)

 

526,956

 

479,557

 

47,399

 

 

 

 

 

Crude oil fixed-price (barrels) (6)

 

13

 

13

 

 

 

 

 

 

Crude oil index-price (barrels) (6)

 

7,982

 

7,982

 

 

 

 

 

 

 


(1)

The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at September 30, 2015. See Note 8 to our condensed consolidated financial statements included in this Quarterly Report for additional information on our Credit Agreement.

 

 

(2)

At September 30, 2015, we had agreements with crude oil and refined products pipeline operators obligating us to minimum throughput payments in exchange for pipeline capacity commitments.

 

 

(3)

At September 30, 2015, we had the following construction commitments:

 

 

 

·

In October 2014, Grand Mesa Pipeline, LLC (“Grand Mesa”) completed a successful open season in which it received the requisite support, in the form of ship-or-pay volume commitments from multiple shippers, to begin construction of a 20-inch pipeline system. We anticipate that the pipeline will commence service in the second half of calendar year 2016. At September 30, 2015, the construction commitments for Grand Mesa were $562.8 million.

 

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·

In February 2015, we acquired Sawtooth, which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets. As part of this acquisition, we also entered into a construction agreement to expand the storage capacity of the facility. We anticipate this project will be completed by the end of calendar year 2015. At September 30, 2015, the construction commitments for this project were $21.8 million.

 

(4)

At September 30, 2015, we had the following purchase commitments (in thousands):

 

Natural gas liquids fixed-price

 

$

38,073

 

Crude oil fixed-price

 

578

 

 

(5)

At September 30, 2015 , we had the following purchase commitments (in thousands):

 

Natural gas liquids index-price

 

$

264,790

 

Crude oil index-price

 

336,151

 

 

Index prices are based on a forward price curve at September 30, 2015. A theoretical change of $0.10 per gallon in the underlying commodity price at September 30, 2015 would result in a change of $52.7 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel in the underlying commodity price at September 30, 2015 would result in a change of $8.0 million in the value of our index-price crude oil purchase commitments.

 

(6)

At September 30, 2015, we had the following sales contract volumes (in thousands):

 

Natural gas liquids fixed-price (gallons)

 

179,849

 

Natural gas liquids index-price (gallons)

 

253,827

 

Crude oil fixed-price (barrels)

 

1,018

 

Crude oil index-price (barrels)

 

7,842

 

 

Off-Balance Sheet Arrangements

 

We do not have any off balance sheet arrangements other than the operating leases described in Note 10 to our condensed consolidated financial statements included in this Quarterly Report.

 

Environmental Legislation

 

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

 

Trends

 

Crude oil prices can fluctuate widely based on changes in supply and demand conditions. The opportunity to generate revenues in our crude oil logistics business is heavily influenced by the volume of crude oil being produced. Crude oil prices declined sharply during the nine months ended March 31, 2015 (the spot price for NYMEX West Texas Intermediate crude oil at Cushing, Oklahoma declined from $105.34 per barrel at July 1, 2014 to $45.09 per barrel at September 30, 2015). While crude oil production in the United States has been strong in recent years, the sharp decline in crude oil prices has reduced the incentive for producers to expand production. If crude oil prices remain low, resultant declines in crude oil production may adversely impact volumes in our crude oil logistics business.

 

Since January 2015, crude oil markets have been in contango (a condition in which the forward crude price is greater than the spot price). Our crude oil logistics business benefits when the market is in contango, as increasing prices result in inventory holding gains during the time between when we purchase inventory and when we sell it. In addition, we are able to better use our storage assets when crude oil markets are in contango.

 

Our opportunity to generate revenues in our water solutions business is based on the level of production of natural gas and crude oil in the areas where our facilities are located. As described above, crude oil prices declined sharply during the year ended

 

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March 31, 2015. At current market prices, producers may reduce drilling activity, which could have an adverse impact on the volumes of our water solutions business.

 

A portion of the revenues of our water solutions business is generated from the sale of hydrocarbons that we recover when processing the wastewater. Because of this, lower crude oil prices result in lower per barrel revenues for our water solutions business.

 

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

 

During the three months ended September 30, 2015, prices for refined products declined. Gulf Coast prices, on which our sales contracts are based, declined more than the New York Harbor prices, on which our futures contracts are based, which had an adverse impact on our weighted-average cost of sales. Based on historical experience, we generally expect the spreads between Gulf Coast and New York Harbor prices to be more consistent over the course of a contract year than during any individual quarter within the year, and that we should expect more volatility in weighted-average cost of sales among quarters within a fiscal year than we would expect during a full fiscal year.

 

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

 

Recent Accounting Pronouncements

 

In July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015—11, “Simplifying the Measurement of Inventory.” ASU No. 2015—11 requires that inventory within the scope of the guidance be measured at the lower of cost or net realizable value. The ASU is effective for the Partnership beginning April 1, 2017, although early adoption is permitted. We do not expect the adoption of this ASU to have a material impact on our current accounting policies.

 

In April 2015, the FASB issued ASU No. 2015—03, “Simplifying the Presentation of Debt Issuance Costs.” ASU No. 2015—03 requires that debt issuance costs (excluding costs associated with revolving debt arrangements) be presented in the balance sheet as a reduction to the carrying amount of the debt. We plan to adopt this ASU effective March 31, 2016, when we will begin presenting debt issuance costs as a reduction to long-term debt, rather than as an intangible asset. At September 30, 2015, intangible assets on our condensed consolidated balance sheet include $16.1 million of debt issuance costs associated with our senior notes that, upon adoption of ASU No. 2015—03, would be reclassified as a reduction to long-term debt. The ASU requires retrospective application for all prior periods presented. At March 31, 2015, intangible assets on our condensed consolidated balance sheet include $17.8 million of debt issuance costs associated with our senior notes that, upon adoption of ASU No. 2015—03, will be reclassified as a reduction to long-term debt.

 

In May 2014, the FASB issued ASU No. 2014—09, “Revenue from Contracts with Customers.” ASU No. 2014—09 will replace most existing revenue recognition guidance in GAAP. The core principle of this ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU is effective for the Partnership beginning April 1, 2018, and allows for both full retrospective and modified retrospective (with cumulative effect) methods of adoption. We are in the process of determining the method of adoption and assessing the impact of this ASU on our consolidated financial statements.

 

Critical Accounting Policies

 

The preparation of financial statements and related disclosures in conformity with GAAP requires the selection and application of appropriate accounting principles to the relevant facts and circumstances of the Partnership’s operations and the use of estimates made by management. We have identified the following accounting policies that are most important to the portrayal of our financial condition and results of operations. The application of these accounting policies, which requires subjective or complex judgments regarding estimates and projected outcomes of future events, and changes in these accounting policies, could have a material effect on our consolidated financial statements.

 

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Revenue Recognition

 

We record product sales revenues when title to the product transfers to the purchaser, which typically occurs when the purchaser receives the product. We record terminaling, transportation, storage, and service revenues when the service is performed, and we record tank and other rental revenues over the lease term. Several of our terminaling service agreements with throughput customers allow us to receive the product volume gained resulting from differences between the measurement of product volumes received and distributed at our terminaling facilities. Such differences are due to the inherent variances in measurement devices and methodology. We record revenues for the net proceeds from the sale of the product gained. Revenues for our water solutions segment are recognized when we obtain the wastewater at our treatment and disposal facilities.

 

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. We include amounts billed to customers for shipping and handling costs in revenues in our condensed consolidated statements of operations.

 

We enter into certain contracts whereby we agree to purchase product from a counterparty and sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into at the same time and are entered into in contemplation of each other, we record the revenues for these transactions net of cost of sales.

 

Impairment of Long-Lived Assets

 

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

 

Crude oil prices decreased significantly during our prior fiscal year, and crude oil prices have remained low during our current fiscal year. This has had an unfavorable impact on our water solutions business. The volume of water we process is driven in part by the level of crude oil production, and the lower crude oil prices have given producers less incentive to expand production. In addition, a significant portion of the revenues of our water solutions business are generated from the sale of crude oil that we recover in the process of treating the wastewater, and low crude oil prices have an adverse impact on these revenues. We will consider these factors in preparing our goodwill impairment assessment during the fourth quarter of our fiscal year. Our water solutions segment has $467.1 million of goodwill at September 30, 2015. If we later conclude that this goodwill is impaired, we will record a reduction to goodwill and a related impairment expense.

 

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

 

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

 

Asset Retirement Obligations

 

We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value can be made. In order to determine the fair value of such a liability, we must make certain estimates and assumptions including, among other things, projected cash flows, the estimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time. Our condensed consolidated balance sheet at September 30, 2015 includes a liability of $4.8 million related to asset retirement obligations, which is reported within other noncurrent liabilities. This liability is related to contractual and regulatory obligations at certain facilities for which we have to perform remediation, dismantlement, or removal activities when the assets are retired.

 

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

 

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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.

 

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

 

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

 

Amortization of Intangible Assets

 

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

 

Tank Bottoms

 

Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost within property, plant and equipment on our condensed consolidated balance sheets. We recover tank bottoms when the storage tanks are removed from service. The following table summarizes the tank bottoms reported in our condensed consolidated balance sheet at September 30, 2015:

 

 

 

Volume

 

 

 

Product

 

(in barrels)

 

Value

 

 

 

(in thousands)

 

Gasoline

 

219

 

$

25,710

 

Crude oil

 

231

 

19,320

 

Diesel

 

121

 

14,753

 

Renewables

 

41

 

4,220

 

Other

 

12

 

738

 

Total

 

 

 

$

64,741

 

 

Linefill

 

We have entered into long-term commitments to ship specified minimum volumes of crude oil on certain third-party owned pipelines. These agreements require that we maintain a certain minimum amount of crude oil in the pipeline to serve as linefill over the duration of the agreement. We report such linefill at historical cost within other noncurrent assets on our condensed consolidated balance sheets. At September 30, 2015, linefill was $35.1 million and consisted of 487,104 barrels of crude oil.

 

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Business Combinations

 

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

 

Inventories

 

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

 

Equity-Based Compensation

 

Our general partner has granted certain restricted units to employees and directors under a long-term incentive plan. These units vest in tranches, subject to the continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the board of directors.

 

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

 

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

 

We record the expense for each of the tranches of the Performance Awards on a straight-line basis over the period beginning with the grant date and ending with the vesting date of the tranche. At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using a Monte Carlo simulation.

 

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

 

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Table of Contents

 

Item 3.                    Quantitative and Qualitative Disclosures About Market Risk

 

Interest Rate Risk

 

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

 

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At September 30, 2015, we had $1.739 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 2.21%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $2.2 million, based on borrowings outstanding at September 30, 2015.

 

The TLP Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At September 30, 2015, TLP had $249.6 million of outstanding borrowings under the TLP Credit Facility at a rate of 2.72%. A change in interest rates of 0.125% would result in an increase or decrease in TLP’s annual interest expense of $0.3 million, based on borrowings outstanding at September 30, 2015.

 

Commodity Price and Credit Risk

 

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

 

Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions. At September 30, 2015, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.

 

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

 

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

 

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Table of Contents

 

Although we use financial derivative instruments to reduce the market price risk associated with forecasted transactions, we do not account for financial derivative transactions as hedges. We record the changes in fair value of these financial derivative transactions within cost of sales. The following table summarizes the hypothetical impact on the September 30, 2015 fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands):

 

 

 

Increase

 

 

 

(Decrease)

 

 

 

To Fair Value

 

 

 

 

 

Crude oil (crude oil logistics segment)

 

$

(4,063

)

Crude oil (water solutions segment)

 

(3,077

)

Propane (liquids segment)

 

1,956

 

Other products (liquids segment)

 

(325

)

Refined products (refined products and renewables segment)

 

(15,995

)

Renewables (refined products and renewables segment)

 

(10,950

)

 

Fair Value

 

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

 

Item 4.                    Controls and Procedures

 

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

 

We completed an evaluation under the supervision and with participation of our management, including the principal executive officer and principal financial officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures at September 30, 2015. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of September 30, 2015, such disclosure controls and procedures were effective to provide the reasonable assurance described above.

 

Other than changes that have resulted or may result from our acquisition of TransMontaigne, as discussed below, there have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)—15(f) of the Exchange Act) during the three months ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

 

We acquired TransMontaigne and certain related operations in July 2014, as described in Note 4 to our condensed consolidated financial statements included in this Quarterly Report. At this time, we continue to evaluate the business and internal controls and processes associated with TransMontaigne and are making various changes to its operating and organizational structure based on our business plan. We are in the process of implementing our internal control structure over this acquired business. We expect that our evaluation and integration efforts related to these operations will continue into future fiscal quarters.

 

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PART II

 

Item 1.                    Legal Proceedings

 

For information related to legal proceedings, please see the discussion under the caption “Legal Contingencies” in Note 10 to our unaudited condensed consolidated financial statements in Part I, Item 1, of this Quarterly Report on Form 10—Q, which information is incorporated by reference into this Item 1.

 

Item 1A.           Risk Factors

 

There have been no material changes in the risk factors previously disclosed in Part I, Item 1A—“Risk Factors” in our Annual Report on Form 10—K for the year ended March 31, 2015.

 

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

 

Unit Repurchase Program

 

On September 10, 2015, the Board of Directors of our general partner authorized a unit repurchase program, under which we may repurchase up to $45 million of our outstanding common units through March 31, 2016. We may repurchase units from time to time in the open market or in other privately negotiated transactions. The unit repurchase program authorization does not obligate us to repurchase any dollar amount or number of our units. The following table summarizes the repurchase of common units during the three months ended September 30, 2015.

 

 

 

 

 

 

 

Total Number of

 

 

 

 

 

 

 

 

 

Common Units

 

Approximate Dollar Value

 

 

 

Total Number of

 

Average Price

 

Purchased as Part

 

of Common Units

 

 

 

Common Units

 

Paid Per

 

of Publicly Announced

 

that May Yet Be Purchased

 

Period

 

Purchased

 

Common Unit

 

Program

 

Under the Program

 

 

 

 

 

 

 

 

 

 

 

July 1—31, 2015

 

 

 

 

 

August 1—31, 2015

 

 

 

 

 

September 1—30, 2015

 

157,626

 

$

23.16

 

157,626

 

$

41,349,748

 

Total

 

157,626

 

$

23.16

 

157,626

 

$

41,349,748

 

 

Item 3.          Defaults Upon Senior Securities

 

Not applicable.

 

Item 4.          Mine Safety Disclosures

 

Not applicable.

 

Item 5.          Other Information

 

None.

 

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Table of Contents

 

Item 6.          Exhibits

 

Exhibit Number

 

Exhibit

 

 

 

4.1

*

Sixth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee

4.2

*

Fourth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee

10.1

 

Amendment No. 10 to Credit Agreement, dated as of July 31, 2015 and effective as of July 31, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8—K (File No. 001—35172) filed on August 4, 2015)

12.1

*

Computation of ratios of earnings to fixed charges

31.1

*

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2

*

Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1

*

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2

*

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS

**

XBRL Instance Document

101.SCH

**

XBRL Schema Document

101.CAL

**

XBRL Calculation Linkbase Document

101.DEF

**

XBRL Definition Linkbase Document

101.LAB

**

XBRL Label Linkbase Document

101.PRE

**

XBRL Presentation Linkbase Document

 


 

*

Exhibits filed with this report.

 

 

 

 

**

The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets at September 30, 2015 and March 31, 2015, (ii) Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2015 and 2014, (iii) Condensed Consolidated Statements of Comprehensive Loss for the three months and six months ended September 30, 2015 and 2014, (iv) Condensed Consolidated Statement of Changes in Equity for the six months ended September 30, 2015, (v) Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 2015 and 2014, and (vi) Notes to Condensed Consolidated Financial Statements.

 

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SIGNATURES

 

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

 

 

NGL ENERGY PARTNERS LP

 

 

 

 

By:

NGL Energy Holdings LLC, its general partner

 

 

 

Date: November 9, 2015

 

By:

/s/ H. Michael Krimbill

 

 

 

H. Michael Krimbill

 

 

 

Chief Executive Officer

 

 

 

Date: November 9, 2015

 

By:

/s/ Atanas H. Atanasov

 

 

 

Atanas H. Atanasov

 

 

 

Chief Financial Officer

 

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Table of Contents

 

INDEX TO EXHIBITS

 

Exhibit Number

 

Exhibit

 

 

 

4.1

*

Sixth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee

4.2

*

Fourth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee

10.1

 

Amendment No. 10 to Credit Agreement, dated as of July 31, 2015 and effective as of July 31, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8—K (File No. 001—35172) filed on August 4, 2015)

12.1

*

Computation of ratios of earnings to fixed charges

31.1

*

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2

*

Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1

*

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2

*

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS

**

XBRL Instance Document

101.SCH

**

XBRL Schema Document

101.CAL

**

XBRL Calculation Linkbase Document

101.DEF

**

XBRL Definition Linkbase Document

101.LAB

**

XBRL Label Linkbase Document

101.PRE

**

XBRL Presentation Linkbase Document

 


 

*

Exhibits filed with this report.

 

 

 

 

**

The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets at September 30, 2015 and March 31, 2015, (ii) Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2015 and 2014, (iii) Condensed Consolidated Statements of Comprehensive Loss for the three months and six months ended September 30, 2015 and 2014, (iv) Condensed Consolidated Statement of Changes in Equity for the six months ended September 30, 2015, (v) Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 2015 and 2014, and (vi) Notes to Condensed Consolidated Financial Statements.

 

105


Exhibit 4.1

 

SIXTH SUPPLEMENTAL INDENTURE

 

SIXTH SUPPLEMENTAL INDENTURE, dated as of August 21, 2015 (this “ Supplemental Indenture ”), among NGL Energy Partners LP, a Delaware limited partnership (“ NGL LP ”), NGL Energy Finance Corp., a Delaware corporation (“ Finance Corp. ,” and, together with NGL LP, the “ Issuers ”) and Sawtooth NGL Caverns, LLC, a Delaware limited liability company and NGL Supply Terminal Solution Mining, LLC, a Utah limited liability company, each a subsidiary of NGL LP (together, the “ Guaranteeing Subsidiaries ” and each, a “ Guaranteeing Subsidiary ”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “ Trustee ”).

 

W I T N E S S E T H

 

WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee an indenture, dated as of October 16, 2013 (the “ Original Indenture ”), providing for the issuance by the Issuers of 6.875% Senior Notes due 2021 (the “ Notes ”);

 

WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the First Supplemental Indenture, dated as of December 2, 2013 (the “ First Supplemental Indenture ”), pursuant to which certain subsidiaries of NGL LP became Guarantors;

 

WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the Second Supplemental Indenture, dated as of April 22, 2014 (the “ Second Supplemental Indenture ”), pursuant to which certain subsidiaries of NGL LP became Guarantors;

 

WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the Third Supplemental Indenture, dated as of July 31, 2014 (the “ Third Supplemental Indenture ”), pursuant to which certain subsidiaries of NGL LP became Guarantors;

 

WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the Fourth Supplemental Indenture, dated as of December 1, 2014 (the “ Fourth Supplemental Indenture ”), pursuant to which certain subsidiaries of NGL LP became Guarantors;

 

WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the Fifth Supplemental Indenture, dated as of February 17, 2015 (the “ Fifth Supplemental Indenture ”), pursuant to which certain subsidiaries of NGL LP became Guarantors;

 



 

WHEREAS, the Original Indenture as amended and supplemented by the First Supplemental Indenture, the Second Supplemental Indenture, the Third Supplemental Indenture, the Fourth Supplemental Indenture and the Fifth Supplemental Indenture, is referred to herein as the “ Indenture ”;

 

WHEREAS, the Indenture provides that under certain circumstances, a Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which such Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “ Note Guarantee ”); and

 

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

 

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

 

1.                                       CAPITALIZED TERMS.  Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

 

2.                                       AGREEMENT TO GUARANTEE.  Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Note Guarantee and in the Indenture including but not limited to Article 10 thereof.

 

3.                                       EXECUTION AND DELIVERY.  Each Guaranteeing Subsidiary agrees that the Note Guarantees shall remain in full force and effect notwithstanding any failure to endorse on each Note a notation of such Note Guarantee.

 

4.                                       NO RECOURSE AGAINST OTHERS.  No past, present or future director, officer, partner, employee, incorporator, organizer, manager, unitholder or other owner of Capital Stock (as defined in the Indenture) of any Guaranteeing Subsidiary or agent thereof, as such, shall have any liability for any obligations of the Issuers, the Guarantors, or any Guaranteeing Subsidiary or any other Subsidiary of an Issuer providing a Note Guarantee under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation.  Each Holder of the Notes by accepting a Note waives and releases all such liability.  The waiver and release are part of the consideration for issuance of the Notes.  Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

 

5.                                       NEW YORK LAW TO GOVERN.  THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

 

2



 

6.                                       COUNTERPARTS.  The parties may sign any number of copies of this Supplemental Indenture.  Each signed copy shall be an original, but all of them together represent the same agreement.

 

7.                                       EFFECT OF HEADINGS.  The Section headings herein are for convenience only and shall not affect the construction hereof.

 

8.                                       THE TRUSTEE.  The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers.

 

[Signature Pages Follow]

 

3



 

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

 

 

 

 

GUARANTEEING SUBSIDIARIES:

 

 

 

SAWTOOTH NGL CAVERNS, LLC

 

NGL SUPPLY TERMINAL SOLUTION MINING, LLC

 

 

 

 

By:

/s/ Atanas H. Atanasov

 

 

Name:

Atanas H. Atanasov

 

 

Title:

Executive Vice President, Chief Financial Officer

 

 

 

and Treasurer

 

 

 

ISSUERS:

 

 

 

NGL ENERGY PARTNERS LP

 

 

 

 

By:

NGL Energy Holdings, LLC,

 

 

its general partner

 

 

 

 

 

 

By:

/s/ Atanas H. Atanasov

 

 

Name:

Atanas H. Atanasov

 

 

Title:

Executive Vice President, Chief Financial Officer

 

 

 

and Treasurer

 

 

 

NGL ENERGY FINANCE CORP.

 

 

 

 

 

 

By:

/s/ Atanas H. Atanasov

 

 

Name:

Atanas H. Atanasov

 

 

Title:

Senior Vice President, Chief Financial Officer

 

 

 

and Secretary

 

 

 

EXISTING GUARANTORS:

 

 

 

NGL ENERGY OPERATING LLC

 

NGL LIQUIDS, LLC

 

HICKSGAS, LLC

 

NGL PROPANE, LLC

 

NGL SUPPLY TERMINAL COMPANY, LLC

 

NGL SUPPLY WHOLESALE, LLC

 

OSTERMAN PROPANE, LLC

 

NGL-NE REAL ESTATE, LLC

 

NGL-MA REAL ESTATE, LLC

 

NGL-MA, LLC

 

( Signature Page to Sixth Supplemental Indenture )

 



 

 

NGL CRUDE LOGISTICS, LLC

 

NGL ENERGY HOLDINGS II, LLC

 

NGL ENERGY LOGISTICS, LLC

 

NGL CRUDE TERMINALS, LLC

 

NGL CRUDE CUSHING, LLC

 

NGL CRUDE PIPELINES, LLC

 

NGL SHIPPING AND TRADING, LLC

 

ANTICLINE DISPOSAL, LLC

 

CENTENNIAL ENERGY, LLC

 

CENTENNIAL GAS LIQUIDS ULC

 

HIGH SIERRA CRUDE OIL & MARKETING, LLC

 

NGL WATER SOLUTIONS DJ, LLC

 

ANDREWS OIL BUYERS, INC.

 

NGL MARINE, LLC

 

NGL WATER SOLUTIONS EAGLE FORD, LLC

 

NGL WATER SOLUTIONS, LLC

 

NGL CRUDE CANADA HOLDINGS, LLC

 

NGL WATER SOLUTIONS PERMIAN, LLC

 

NGL CRUDE TRANSPORTATION, LLC

 

NGL WATER SOLUTIONS MID-CONTINENT, LLC

 

NGL MILAN INVESTMENTS, LLC

 

 

 

 

 

 

By:

/s/ Atanas H. Atanasov

 

 

Name:

Atanas H. Atanasov

 

 

Title:

Executive Vice President, Chief Financial Officer

 

 

 

and Treasurer

 

 

 

 

TRANSMONTAIGNE INC.

 

TRANSMONTAIGNE PRODUCT SERVICES INC.

 

TRANSMONTAIGNE SERVICES INC.

 

TRANSMONTAIGNE GP, LLC

 

 

 

 

By:

/s/ Atanas H. Atanasov

 

Name: Atanas H. Atanasov

 

Title: Vice President

 

 

 

 

 

HIGH SIERRA ENERGY OPERATING, LLC

 

 

 

 

By:

/s/ Atanas H. Atanasov

 

 

Name: Atanas H. Atanasov

 

 

Title: Chief Financial Officer

 

( Signature Page to Sixth Supplemental Indenture )

 



 

 

HIGH SIERRA ENERGY LP

 

 

 

 

By:

High Sierra Energy GP, LLC,

 

 

its general partner

 

 

 

 

By:

/s/ Atanas H. Atanasov

 

 

Name: Atanas H. Atanasov

 

 

Title: Chief Financial Officer

 

( Signature Page to Sixth Supplemental Indenture )

 



 

 

TRUSTEE:

 

 

 

U.S. BANK NATIONAL ASSOCIATION, as Trustee

 

 

 

 

 

 

By:

/s/ Damien Daley

 

 

Name: Damien Daley

 

 

Title: Assistant Vice President

 

( Signature Page to Sixth Supplemental Indenture )

 


Exhibit 4.2

 

FOURTH SUPPLEMENTAL INDENTURE

 

FOURTH SUPPLEMENTAL INDENTURE, dated as of August 21, 2015 (this “ Supplemental Indenture ”), among NGL Energy Partners LP, a Delaware limited partnership (“ NGL LP ”), NGL Energy Finance Corp., a Delaware corporation (“ Finance Corp. ,” and, together with NGL LP, the “ Issuers ”) and Sawtooth NGL Caverns, LLC, a Delaware limited liability company and NGL Supply Terminal Solution Mining, LLC, a Utah limited liability company, each a subsidiary of NGL LP (together, the “ Guaranteeing Subsidiaries ” and each, a “ Guaranteeing Subsidiary ”), the other Guarantors (as defined in the Indenture referred to herein), and U.S. Bank National Association, as trustee under the Indenture referred to below (the “ Trustee ”).

 

W I T N E S S E T H

 

WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee an indenture, dated as of July 9, 2014 (the “ Original Indenture ”), providing for the issuance by the Issuers of 5.125% Senior Notes due 2019 (the “ Notes ”);

 

WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the First Supplemental Indenture, dated as of July 31, 2014 (the “ First Supplemental Indenture ”), pursuant to which certain subsidiaries of NGL LP became Guarantors;

 

WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the Second Supplemental Indenture, dated as of December 1, 2014, (the “ Second Supplemental Indenture ”), pursuant to which certain subsidiaries of NGL LP became Guarantors;

 

WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the Third Supplemental Indenture, dated as of February 17, 2015, (the “ Third Supplemental Indenture ”), pursuant to which certain subsidiaries of NGL LP became Guarantors;

 

WHEREAS, the Original Indenture as amended and supplemented by the First Supplemental Indenture, the Second Supplemental Indenture and the Third Supplemental Indenture, is referred to herein as the “ Indenture ”;

 

WHEREAS, the Indenture provides that under certain circumstances, a Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which such Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “ Note Guarantee ”); and

 

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

 



 

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

 

1.                                       CAPITALIZED TERMS.  Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

 

2.                                       AGREEMENT TO GUARANTEE.  Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Note Guarantee and in the Indenture including but not limited to Article 10 thereof.

 

3.                                       EXECUTION AND DELIVERY.  Each Guaranteeing Subsidiary agrees that the Note Guarantees shall remain in full force and effect notwithstanding any failure to endorse on each Note a notation of such Note Guarantee.

 

4.                                       NO RECOURSE AGAINST OTHERS.  No past, present or future director, officer, partner, employee, incorporator, organizer, manager, unitholder or other owner of Capital Stock (as defined in the Indenture) of any Guaranteeing Subsidiary or agent thereof, as such, shall have any liability for any obligations of the Issuers, the Guarantors, or any Guaranteeing Subsidiary or any other Subsidiary of an Issuer providing a Note Guarantee under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation.  Each Holder of the Notes by accepting a Note waives and releases all such liability.  The waiver and release are part of the consideration for issuance of the Notes.  Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

 

5.                                       NEW YORK LAW TO GOVERN.  THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

 

6.                                       COUNTERPARTS.  The parties may sign any number of copies of this Supplemental Indenture.  Each signed copy shall be an original, but all of them together represent the same agreement.

 

7.                                       EFFECT OF HEADINGS.  The Section headings herein are for convenience only and shall not affect the construction hereof.

 

8.                                       THE TRUSTEE.  The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers.

 

2



 

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

 

 

 

 

GUARANTEEING SUBSIDIARIES:

 

 

 

SAWTOOTH NGL CAVERNS, LLC

 

NGL SUPPLY TERMINAL SOLUTION MINING, LLC

 

 

 

 

By:

/s/ Atanas H. Atanasov

 

 

Name:

Atanas H. Atanasov

 

 

Title:

Executive Vice President, Chief Financial Officer

 

 

 

and Treasurer

 

 

 

ISSUERS:

 

 

 

NGL ENERGY PARTNERS LP

 

 

 

 

By:

NGL Energy Holdings, LLC,

 

 

its general partner

 

 

 

 

 

 

 

By:

/s/ Atanas H. Atanasov

 

 

Name:

Atanas H. Atanasov

 

 

Title:

Executive Vice President, Chief Financial Officer

 

 

 

and Treasurer

 

 

 

NGL ENERGY FINANCE CORP.

 

 

 

 

 

 

By:

/s/ Atanas H. Atanasov

 

 

Name:

Atanas H. Atanasov

 

 

Title:

Senior Vice President, Chief Financial Officer and

 

 

 

Secretary

 

 

 

 

 

EXISTING GUARANTORS:

 

 

 

NGL ENERGY OPERATING LLC

 

NGL LIQUIDS, LLC

 

HICKSGAS , LLC

 

NGL PROPANE, LLC

 

NGL SUPPLY TERMINAL COMPANY, LLC

 

NGL SUPPLY WHOLESALE, LLC

 

OSTERMAN PROPANE , LLC

 

NGL-NE REAL ESTATE, LLC

 

NGL- MA REAL ESTATE, LLC

 

( Signature Page to Fourth Supplemental Indenture )

 



 

 

NGL- MA, LLC

 

NGL CRUDE LOGISTICS, LLC

 

NGL ENERGY HOLDINGS II, LLC

 

NGL ENERGY LOGISTICS, LLC

 

NGL CRUDE TERMINALS, LLC

 

NGL CRUDE CUSHING, LLC

 

NGL CRUDE PIPELINES, LLC

 

NGL SHIPPING AND TRADING, LLC

 

ANTICLINE DISPOSAL, LLC

 

CENTENNIAL ENERGY, LLC

 

CENTENNIAL GAS LIQUIDS ULC

 

HIGH SIERRA CRUDE OIL & MARKETING, LLC

 

NGL WATER SOLUTIONS DJ, LLC

 

ANDREWS OIL BUYERS, INC.

 

NGL MARINE, LLC

 

NGL WATER SOLUTIONS EAGLE FORD, LLC

 

NGL WATER SOLUTIONS, LLC

 

NGL CRUDE CANADA HOLDINGS, LLC

 

NGL WATER SOLUTIONS PERMIAN, LLC

 

NGL CRUDE TRANSPORTATION, LLC

 

NGL WATER SOLUTIONS MID-CONTINENT, LLC

 

NGL MILAN INVESTMENTS, LLC

 

NGL WATER SOLUTIONS BAKKEN, LLC

 

GRAND MESA PIPELINE, LLC

 

BLUE GRAMA LAND CORPORATION

 

 

 

 

 

 

By:

/s/ Atanas H. Atanasov

 

 

Name:

Atanas H. Atanasov

 

 

Title:

Executive Vice President, Chief Financial Officer

 

 

 

and Treasurer

 

 

 

TRANSMONTAIGNE INC.

 

TRANSMONTAIGNE PRODUCT SERVICES INC.

 

TRANSMONTAIGNE SERVICES INC.

 

TRANSMONTAIGNE GP, LLC

 

 

 

 

By:

/s/ Atanas H. Atanasov

 

Name: Atanas H. Atanasov

 

Title: Vice President

 

( Signature Page to Fourth Supplemental Indenture )

 



 

 

HIGH SIERRA ENERGY OPERATING, LLC

 

 

 

 

By:

/s/ Atanas H. Atanasov

 

 

Name: Atanas H. Atanasov

 

 

Title: Chief Financial Officer

 

 

 

HIGH SIERRA ENERGY LP

 

 

 

 

By:

High Sierra Energy GP, LLC,

 

 

its general partner

 

 

 

 

By:

/s/ Atanas H. Atanasov

 

 

Name: Atanas H. Atanasov

 

 

Title: Chief Financial Officer

 

( Signature Page to Fourth Supplemental Indenture )

 



 

 

TRUSTEE:

 

 

 

U.S. BANK NATIONAL ASSOCIATION, as Trustee

 

 

 

 

 

 

By:

/s/ Damien Daley

 

 

Name: Damien Daley

 

 

Title: Assistant Vice President

 

( Signature Page to Fourth Supplemental Indenture )

 


Exhibit 12.1

 

NGL ENERGY PARTNERS LP AND SUBSIDIARIES AND NGL SUPPLY, INC.

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(In thousands, except ratio amounts)

 

 

 

NGL Energy Partners LP

 

NGL Supply, Inc.

 

 

 

Six Months

 

 

 

 

 

 

 

 

 

Six Months

 

Six Months

 

 

 

Ended

 

 

 

 

 

 

 

 

 

Ended

 

Ended

 

 

 

September 30,

 

Year Ended March 31,

 

March 31,

 

September 30,

 

 

 

2015

 

2015

 

2014

 

2013

 

2012

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EARNINGS:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) before income taxes

 

$

(64,926

)

$

26,262

 

$

49,695

 

$

50,065

 

$

8,465

 

$

12,679

 

$

(3,977

)

Loss (income) before income taxes attributable to noncontrolling interests

 

(6,766

)

(13,223

)

(1,103

)

(250

)

12

 

 

45

 

Fixed charges

 

84,731

 

151,956

 

91,622

 

66,824

 

9,354

 

2,761

 

597

 

Total earnings (loss)

 

$

13,039

 

$

164,995

 

$

140,214

 

$

116,639

 

$

17,831

 

$

15,440

 

$

(3,335

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

FIXED CHARGES:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

$

62,373

 

$

110,123

 

$

58,854

 

$

32,994

 

$

7,620

 

$

2,482

 

$

372

 

Loss on early extinguishment of debt

 

 

 

 

5,769

 

 

 

 

Portion of rental expense estimated to relate to interest (1)

 

22,358

 

41,833

 

32,768

 

28,061

 

1,734

 

279

 

225

 

Fixed charges

 

$

84,731

 

$

151,956

 

$

91,622

 

$

66,824

 

$

9,354

 

$

2,761

 

$

597

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of earnings to fixed charges

 

 

(2)

1.09

 

1.53

 

1.75

 

1.91

 

5.59

 

 

(3)

 


(1)           Represents one-third of the total operating lease rental expense, which is that portion estimated to represent interest.

 

(2)           The ratio was less than 1:1 for the six months ended September 30, 2015. NGL Energy Partners LP would have needed to generate an additional $71.7 million of earnings to achieve a ratio of 1:1.

 

(3)           The ratio was less than 1:1 for the six months ended September 30, 2010. NGL Supply, Inc. would have needed to generate an additional $3.9 million of earnings to achieve a ratio of 1:1.

 


Exhibit 31.1

 

CERTIFICATION

 

I, H. Michael Krimbill, certify that:

 

1.               I have reviewed this Quarterly Report on Form 10—Q of NGL Energy Partners LP;

 

2.               Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.               Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4.               The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a—15(e) and 15d—15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a—15(f) and 15d—15(f)) for the registrant and have:

 

a.               Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b.               Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c.                Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d.               Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

5.               The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

 

a.               All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b.               Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

Date: November 9, 2015

/s/ H. Michael Krimbill

 

H. Michael Krimbill

 

Chief Executive Officer of NGL Energy Holdings LLC,
the general partner of NGL Energy Partners LP

 


Exhibit 31.2

 

CERTIFICATION

 

I, Atanas H. Atanasov, certify that:

 

1.               I have reviewed this Quarterly Report on Form 10—Q of NGL Energy Partners LP;

 

2.               Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.               Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4.               The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a—15(e) and 15d—15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a—15(f) and 15d—15(f)) for the registrant and have:

 

a.               Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b.               Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c.                Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d.               Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

5.               The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

 

a.               All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b.               Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

Date: November 9, 2015

/s/ Atanas H. Atanasov

 

Atanas H. Atanasov

 

Chief Financial Officer of NGL Energy Holdings LLC,
the general partner of NGL Energy Partners LP

 


Exhibit 32.1

 

CERTIFICATION
PURSUANT TO 18 U.S.C. SECTION 1350

 

In connection with the Quarterly Report of NGL Energy Partners LP (the “ Partnership ”) on Form 10—Q for the fiscal quarter ended September 30, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “ Report ”), I, H. Michael Krimbill, Chief Executive Officer of NGL Energy Holdings LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“ Section 906 ”), that, to my knowledge:

 

1.               The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

 

2.               The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

 

Date: November 9, 2015

/s/ H. Michael Krimbill

 

H. Michael Krimbill

 

Chief Executive Officer of NGL Energy Holdings LLC,

 

the general partner of NGL Energy Partners LP

 

This certification is being furnished solely pursuant to Section 906 and is not being filed as part of the Report or as a separate disclosure document.

 

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

 


Exhibit 32.2

 

CERTIFICATION
PURSUANT TO 18 U.S.C. SECTION 1350

 

In connection with the Quarterly Report of NGL Energy Partners LP (the “ Partnership ”) on Form 10—Q for the fiscal quarter ended September 30, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “ Report ”), I, Atanas H. Atanasov, Chief Financial Officer of NGL Energy Holdings LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“ Section 906 ”), that, to my knowledge:

 

1.               The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

 

2.               The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

 

Date: November 9, 2015

/s/ Atanas H. Atanasov

 

Atanas H. Atanasov

 

Chief Financial Officer of NGL Energy Holdings LLC,

 

the general partner of NGL Energy Partners LP

 

This certification is being furnished solely pursuant to Section 906 and is not being filed as part of the Report or as a separate disclosure document.

 

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.