Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

x

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

 

For the quarterly period ended September 30, 2013

 

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 o

 

Accelerated filer x

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

 

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

 

As of November 5, 2013, there were 66,650,735 common units and 5,919,346 subordinated units issued and outstanding.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

PART I

 

 

 

Item 1.

Financial Statements (Unaudited)

3

 

 

 

 

Condensed Consolidated Balance Sheets as of September 30, 2013 and March 31, 2013

3

 

Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2013 and 2012

4

 

Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and six months ended September 30, 2013 and 2012

5

 

Condensed Consolidated Statement of Changes in Partners’ Equity for the six months ended September 30, 2013

6

 

Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 2013 and 2012

7

 

Notes to Condensed Consolidated Financial Statements

8

 

 

 

Item 2.

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

38

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

69

Item 4.

Controls and Procedures

70

 

 

 

PART II

 

 

 

Item 1.

Legal Proceedings

71

Item 1A.

Risk Factors

71

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

71

Item 3.

Defaults Upon Senior Securities

71

Item 4.

Mine Safety Disclosures

71

Item 5.

Other Information

71

Item 6.

Exhibits

72

 

 

 

Signatures

 

74

 

 

 

Exhibit Index

 

75

 

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Forward-Looking Statements

 

This Quarterly Report on Form 10-Q 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. When used in this quarterly report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our general partner can give assurances that such expectations 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 anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:

 

·                  the prices and market demand for crude oil and natural gas liquids;

 

·                  energy prices generally;

 

·                  the price of propane compared to the price of alternative and competing fuels;

 

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

 

·                  the general level of demand for crude oil and natural gas liquids;

 

·                  the availability of supply of crude oil and natural gas liquids;

 

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

 

·                  the ability to obtain adequate supplies of propane and distillates for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane to market areas;

 

·                  actions taken by foreign oil and gas producing nations;

 

·                  the political and economic stability of petroleum producing nations;

 

·                  the effect of weather conditions on demand for oil, natural gas and natural gas liquids;

 

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

 

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

 

·                  availability and marketing of competitive fuels;

 

·                  the impact of energy conservation efforts;

 

·                  energy efficiencies and technological trends;

 

·                  governmental regulation and taxation;

 

·                  the impact of legislative and regulatory actions on hydraulic fracturing;

 

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

 

·                  the maturity of the propane industry and competition from other propane distributors;

 

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·                  loss of key personnel;

 

·                  the ability to renew contracts with key customers;

 

·                  the fees we charge and the margins we realize for our terminal services;

 

·                  the ability to renew leases for general purpose and high pressure rail cars;

 

·                  the ability to renew leases for underground natural gas liquids storage;

 

·                  the non-payment or nonperformance by our customers;

 

·                  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 at purchase prices that are accretive to our financial results;

 

·                  the ability to successfully integrate acquired assets and businesses;

 

·                  changes in laws and regulations to which we are subject, 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, including our sales of crude oil, condensate, and natural gas liquids, our processing of wastewater, and transportation and hedging activities; and

 

·                  the costs and effects of legal and administrative proceedings.

 

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 “Item 1A — Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended March 31, 2013.

 

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PART I

 

Item 1.                                 Financial Statements (Unaudited)

 

NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Balance Sheets

As of September 30, 2013 and March 31, 2013

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

 

 

 

September 30,

 

March 31,

 

 

 

2013

 

2013

 

ASSETS

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

 

$

5,528

 

$

11,561

 

Accounts receivable - trade, net of allowance for doubtful accounts of $1,893 and $1,760, respectively

 

602,033

 

562,889

 

Accounts receivable - affiliates

 

3,071

 

22,883

 

Inventories

 

355,300

 

126,895

 

Prepaid expenses and other current assets

 

47,927

 

37,891

 

Total current assets

 

1,013,859

 

762,119

 

 

 

 

 

 

 

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $76,390 and $50,127, respectively

 

631,663

 

516,937

 

GOODWILL

 

840,287

 

563,146

 

INTANGIBLE ASSETS, net of accumulated amortization of $68,790 and $44,155, respectively

 

534,746

 

442,603

 

OTHER NONCURRENT ASSETS

 

5,938

 

6,542

 

Total assets

 

$

3,026,493

 

$

2,291,347

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Trade accounts payable

 

$

604,018

 

$

535,687

 

Accrued expenses and other payables

 

101,988

 

85,703

 

Advance payments received from customers

 

67,994

 

22,372

 

Accounts payable - affiliates

 

18,429

 

6,900

 

Current maturities of long-term debt

 

8,229

 

8,626

 

Total current liabilities

 

800,658

 

659,288

 

 

 

 

 

 

 

LONG-TERM DEBT, net of current maturities

 

906,066

 

740,436

 

OTHER NONCURRENT LIABILITIES

 

2,673

 

2,205

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES

 

 

 

 

 

 

 

 

 

 

 

PARTNERS’ EQUITY, per accompanying statement:

 

 

 

 

 

General Partner — 0.1% interest; 71,288 and 53,676 notional units outstanding at September 30, 2013 and March 31, 2013, respectively

 

(48,782

)

(50,497

)

Limited Partners — 99.9% interest — Common units — 65,296,884 and 47,703,313 units outstanding at September 30, 2013 and March 31, 2013, respectively

 

1,354,305

 

920,998

 

Subordinated units — 5,919,346 units outstanding at September 30, 2013 and March 31, 2013

 

4,130

 

13,153

 

Accumulated other comprehensive income (loss) — Foreign currency translation

 

(6

)

24

 

Noncontrolling interests

 

7,449

 

5,740

 

Total partners’ equity

 

1,317,096

 

889,418

 

Total liabilities and partners’ equity

 

$

3,026,493

 

$

2,291,347

 

 

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

 

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NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Statements of Operations

Three Months and Six Months Ended September 30, 2013 and 2012

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

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

REVENUES:

 

 

 

 

 

 

 

 

 

Crude oil logistics

 

$

1,014,008

 

$

711,021

 

$

1,944,802

 

$

784,538

 

Water services

 

34,190

 

15,810

 

54,703

 

17,751

 

Natural gas liquids logistics

 

484,874

 

350,368

 

845,833

 

541,985

 

Retail propane

 

59,380

 

57,003

 

131,597

 

116,211

 

Other

 

1,485

 

1,308

 

2,959

 

1,461

 

Total Revenues

 

1,593,937

 

1,135,510

 

2,979,894

 

1,461,946

 

 

 

 

 

 

 

 

 

 

 

COST OF SALES:

 

 

 

 

 

 

 

 

 

Crude oil logistics

 

992,135

 

693,687

 

1,901,354

 

770,570

 

Water services

 

3,782

 

2,054

 

4,365

 

2,670

 

Natural gas liquids logistics

 

459,394

 

328,283

 

809,645

 

512,328

 

Retail propane

 

33,539

 

29,666

 

76,562

 

67,107

 

Total Cost of Sales

 

1,488,850

 

1,053,690

 

2,791,926

 

1,352,675

 

 

 

 

 

 

 

 

 

 

 

OPERATING COSTS AND EXPENSES:

 

 

 

 

 

 

 

 

 

Operating

 

55,769

 

39,431

 

104,814

 

62,769

 

General and administrative

 

14,312

 

10,443

 

32,766

 

20,403

 

Depreciation and amortization

 

25,061

 

13,361

 

47,785

 

22,588

 

Operating Income

 

9,945

 

18,585

 

2,603

 

3,511

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

 

Interest expense

 

(11,060

)

(8,692

)

(21,682

)

(12,492

)

Loss on early extinguishment of debt

 

 

 

 

(5,769

)

Interest income

 

266

 

263

 

664

 

629

 

Other, net

 

153

 

3

 

(195

)

29

 

Income (Loss) Before Income Taxes

 

(696

)

10,159

 

(18,610

)

(14,092

)

 

 

 

 

 

 

 

 

 

 

INCOME TAX (PROVISION) BENEFIT

 

(236

)

(77

)

170

 

(536

)

 

 

 

 

 

 

 

 

 

 

Net Income (Loss)

 

(932

)

10,082

 

(18,440

)

(14,628

)

 

 

 

 

 

 

 

 

 

 

Net Income Allocated to General Partner

 

(2,451

)

(694

)

(4,139

)

(789

)

 

 

 

 

 

 

 

 

 

 

Net (Income) Loss Attributable to Noncontrolling Interests

 

(9

)

(9

)

(134

)

51

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Attributable to Parent Equity Allocated to Limited Partners

 

$

(3,392

)

$

9,379

 

$

(22,713

)

$

(15,366

)

 

 

 

 

 

 

 

 

 

 

Basic and Diluted Income (Loss) per Common Unit

 

$

(0.05

)

$

0.18

 

$

(0.37

)

$

(0.37

)

 

 

 

 

 

 

 

 

 

 

Basic and Diluted Income (Loss) per Subordinated Unit

 

$

(0.09

)

$

0.18

 

$

(0.52

)

$

(0.38

)

 

 

 

 

 

 

 

 

 

 

Basic and Diluted Weighted Average Units Outstanding:

 

 

 

 

 

 

 

 

 

Common

 

58,909,389

 

44,831,836

 

53,336,969

 

35,730,492

 

Subordinated

 

5,919,346

 

5,919,346

 

5,919,346

 

5,919,346

 

 

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

 

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NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)

Three Months and Six Months Ended September 30, 2013 and 2012

(U.S. Dollars in Thousands)

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(932

)

$

10,082

 

$

(18,440

)

$

(14,628

)

Other comprehensive income (loss), net of tax:

 

 

 

 

 

 

 

 

 

Change in foreign currency translation adjustment

 

(5

)

10

 

(30

)

(3

)

Comprehensive income (loss)

 

$

(937

)

$

10,092

 

$

(18,470

)

$

(14,631

)

 

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

 

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NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Statement of Changes in Partners’ Equity

Six Months Ended September 30, 2013

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

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

 

 

 

 

 

 

 

 

Limited Partners

 

Comprehensive

 

 

 

Total

 

 

 

General

 

Common

 

 

 

Subordinated

 

 

 

Income

 

Noncontrolling

 

Partners’

 

 

 

Partner

 

Units

 

Amount

 

Units

 

Amount

 

(Loss)

 

Interests

 

Equity

 

BALANCES, MARCH 31, 2013

 

$

(50,497

)

47,703,313

 

$

920,998

 

5,919,346

 

$

13,153

 

$

24

 

$

5,740

 

$

889,418

 

Distributions

 

(2,928

)

 

(51,581

)

 

(5,749

)

 

(365

)

(60,623

)

Contributions

 

504

 

 

 

 

 

 

1,940

 

2,444

 

Sales of units in public offerings, net of issuance costs

 

 

14,450,000

 

415,089

 

 

 

 

 

415,089

 

Units issued in business combinations, net of offering costs

 

 

2,860,879

 

80,619

 

 

 

 

 

80,619

 

Equity issued pursuant to incentive compensation plan

 

 

282,692

 

8,619

 

 

 

 

 

8,619

 

Net income (loss)

 

4,139

 

 

(19,439

)

 

(3,274

)

 

134

 

(18,440

)

Foreign currency translation adjustment

 

 

 

 

 

 

(30

)

 

(30

)

BALANCES, SEPTEMBER 30, 2013

 

$

(48,782

)

65,296,884

 

$

1,354,305

 

5,919,346

 

$

4,130

 

$

(6

)

$

7,449

 

$

1,317,096

 

 

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

 

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NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Statements of Cash Flows

Six Months Ended September 30, 2013 and 2012

(U.S. Dollars in Thousands)

 

 

 

Six Months Ended

 

 

 

September 30,

 

 

 

2013

 

2012

 

OPERATING ACTIVITIES:

 

 

 

 

 

Net loss

 

$

(18,440

)

$

(14,628

)

Adjustments to reconcile net loss to net cash used in operating activities:

 

 

 

 

 

Depreciation and amortization, including debt issuance cost amortization

 

51,821

 

25,476

 

Loss on early extinguishment of debt

 

 

5,769

 

Non-cash equity-based compensation expense

 

6,762

 

2,957

 

Loss (gain) on disposal of assets

 

2,163

 

(23

)

Provision for doubtful accounts

 

781

 

356

 

Commodity derivative (gain) loss

 

17,881

 

(5,019

)

Other

 

8

 

72

 

Changes in operating assets and liabilities, exclusive of acquisitions:

 

 

 

 

 

Accounts receivable - trade

 

(27,881

)

101,739

 

Accounts receivable - affiliates

 

19,812

 

6,768

 

Inventories

 

(226,727

)

(121,981

)

Prepaid expenses and other current assets

 

(10,830

)

3,793

 

Trade accounts payable

 

61,093

 

(77,965

)

Accrued expenses and other payables

 

18,065

 

(15,664

)

Accounts payable - affiliates

 

11,529

 

(6,698

)

Advance payments received from customers

 

45,622

 

42,242

 

Net cash used in operating activities

 

(48,341

)

(52,806

)

 

 

 

 

 

 

INVESTING ACTIVITIES:

 

 

 

 

 

Purchases of long-lived assets

 

(67,399

)

(14,595

)

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

 

(393,008

)

(307,082

)

Cash flows from commodity derivatives

 

(19,074

)

10,692

 

Proceeds from sales of assets

 

2,224

 

581

 

Other

 

 

427

 

Net cash used in investing activities

 

(477,257

)

(309,977

)

 

 

 

 

 

 

FINANCING ACTIVITIES:

 

 

 

 

 

Proceeds from borrowings under revolving credit facilities

 

1,061,500

 

594,675

 

Payments on revolving credit facilities

 

(893,000

)

(422,675

)

Issuance of senior notes

 

 

250,000

 

Proceeds from borrowings on other long-term debt

 

880

 

 

Payments on other long-term debt

 

(4,507

)

(251

)

Debt issuance costs

 

(2,218

)

(17,839

)

Contributions

 

2,444

 

751

 

Distributions

 

(60,623

)

(22,883

)

Proceeds from sale of common units, net of offering costs

 

415,089

 

(818

)

Net cash provided by financing activities

 

519,565

 

380,960

 

Net increase (decrease) in cash and cash equivalents

 

(6,033

)

18,177

 

Cash and cash equivalents, beginning of period

 

11,561

 

7,832

 

Cash and cash equivalents, end of period

 

$

5,528

 

$

26,009

 

 

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

 

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Note 1 — Organization and Operations

 

NGL Energy Partners LP (“we”, “our”, or the “Partnership”) is a Delaware limited partnership formed in September 2010. NGL Energy Holdings LLC serves as our general partner. At the time of formation, our operations included a wholesale natural gas liquids business and a retail propane business. We completed an initial public offering in May 2011. Subsequent to our initial public offering, we significantly expanded our operations through a number of business combinations, including the following:

 

·                  During October 2011, we completed a business combination with E. Osterman Propane, Inc., its affiliated companies, and members of the Osterman family, whereby we acquired retail propane operations in the northeastern United States.

 

·                  During November 2011, we completed a business combination with SemStream, L.P. (“SemStream”), whereby we acquired SemStream’s wholesale natural gas liquids supply and marketing operations and its 12 natural gas liquids terminals.

 

·                  During January 2012, we completed a business combination with seven companies associated with Pacer Propane Holding, L.P., whereby we acquired retail propane operations, primarily in the western United States.

 

·                  During February 2012, we completed a business combination with North American Propane, Inc., whereby we acquired retail propane and distillate operations in the northeastern United States.

 

·                  During the year ended March 31, 2012, we completed three additional separate business combination transactions to acquire retail propane operations.

 

·                  On June 19, 2012, we completed a business combination with High Sierra Energy, LP and High Sierra Energy GP, LLC (collectively, “High Sierra”), whereby we acquired all of the ownership interests in High Sierra. High Sierra’s businesses include crude oil gathering, transportation and marketing; water treatment, disposal, and transportation; and natural gas liquids transportation and marketing.

 

·                  On November 1, 2012, we completed a business combination whereby we acquired Pecos Gathering & Marketing, L.L.C. and certain of its affiliated companies (collectively, “Pecos”). The business of Pecos consists primarily of crude oil purchasing and logistics operations in Texas and New Mexico.

 

·                  On December 31, 2012, we completed a business combination whereby we acquired all of the membership interests in Third Coast Towing, LLC (“Third Coast”). The business of Third Coast consists primarily of transporting crude oil via barge.

 

·                  During the year ended March 31, 2013, we completed six additional separate business combination transactions to acquire retail propane and distillate operations, primarily in the northeastern and southeastern United States.

 

·                  During the year ended March 31, 2013, we completed four additional separate acquisitions to expand the assets and operations of our crude oil logistics and water services businesses.

 

·                  During the six months ended September 30, 2013, we completed three acquisitions of retail propane and distillate businesses.

 

·                  On July 1, 2013, we completed a business combination whereby we acquired the assets of Crescent Terminals, LLC and the ownership interests in Cierra Marine, LP and its affiliated companies (collectively, “Crescent”), whereby we acquired four tow boats, seven crude oil barges, and one crude oil terminal in South Texas.

 

·                  On July 2, 2013, we completed a business combination with High Roller Wells Big Lake SWD No. 1, Ltd. (“Big Lake”), whereby we acquired one water disposal facility in West Texas. We also entered into a development agreement that provides us the option to purchase disposal facilities that may be developed in the future.

 

·                  On August 2, 2013, we completed a business combination whereby we acquired seven entities affiliated with Oilfield Water Lines LP (collectively, “OWL”). The businesses of OWL include water disposal operations and a water transportation business in Texas.

 

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Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

·                  On September 1, 2013, we completed a business combination whereby we acquired a crude oil marketing business in Oklahoma and Texas.

 

·                  On September 3, 2013, we completed a business combination with Coastal Plains Disposal #1, LLC (“Coastal”), in which we acquired the ownership interests in a water disposal facility in Texas.

 

As of September 30, 2013, our businesses include:

 

·                  A crude oil logistics business, the assets of which include crude oil terminals, pipeline injection stations, a fleet of trucks, a fleet of leased rail cars, and a fleet of barges and tow boats. Our crude oil logistics business purchases crude oil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

 

·                  A water services business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks. Our water services business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons.

 

·                  Our natural gas liquids logistics business, which supplies natural gas liquids to retailers, wholesalers, and refiners throughout the United States and in Canada, and which provides natural gas liquids terminaling services through its 17 terminals throughout the United States and rail car transportation services through its fleet of owned and predominantly leased rail cars. Our natural gas liquids logistics segment purchases propane, butane, and other natural gas liquids from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets.

 

·                  Our retail propane business, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain re-sellers in more than 20 states.

 

Note 2 — Significant Accounting Policies

 

Basis of Presentation

 

The unaudited condensed consolidated financial statements as of and for the three months and six months ended September 30, 2013 and 2012 include our accounts and those of our controlled subsidiaries. All significant intercompany transactions and account balances have been eliminated in consolidation. The unaudited condensed consolidated balance sheet as of March 31, 2013 is derived from audited financial statements. We have made certain reclassifications to the prior period financial statements to conform with classification methods used in the current fiscal year. These reclassifications had no impact on previously-reported amounts of total assets, liabilities, partners’ equity, or net income.

 

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim consolidated financial information and in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). The unaudited condensed consolidated financial statements include all adjustments that we consider necessary for a fair presentation of the financial position and results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed consolidated financial statements do not include all the 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 not misleading. These interim unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements for the fiscal year ended March 31, 2013 included in our Annual Report on Form 10-K. Due to the seasonal nature of our natural gas liquids operations and other factors, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

 

Use of Estimates

 

The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates.

 

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Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

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 on Form 10-K for the year ended March 31, 2013.

 

Revenue Recognition

 

We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. We record terminaling, storage and service revenues at the time the service is performed and we record tank and other rentals over the term of the lease. Revenues for the wastewater disposal business are recognized upon receipt of the wastewater at our disposal facilities.

 

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. Amounts billed to customers for shipping and handling costs are included in revenues in the consolidated statements of operations. Shipping and handling costs associated with product sales are included in operating expenses in the consolidated statements of operations.

 

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

 

Fair Value Measurements

 

We apply fair value measurements to certain assets and liabilities, principally our commodity derivative instruments and assets and liabilities acquired in business combinations. 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, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

 

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

 

·                  Level 1 — Quoted prices (unadjusted) 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 quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity price swap and option contracts and interest rate protection agreements. The majority of our fair value measurements related to our derivative financial instruments were categorized as Level 2 at September 30, 2013 and March 31, 2013 (see Note 11). We determine the fair value of all our derivative financial instruments utilizing pricing models for significantly similar instruments. Inputs to the pricing model 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. We did not have any fair value measurements categorized as Level 3 at September 30, 2013 or March 31, 2013.

 

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

 

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Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

hierarchy. Assessing the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability.

 

Supplemental Cash Flow Information

 

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

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(in thousands)

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Interest paid, exclusive of debt issuance costs

 

$

8,423

 

$

6,594

 

$

16,908

 

$

9,831

 

Income taxes paid

 

$

369

 

$

 

$

650

 

$

176

 

 

 

 

 

 

 

 

 

 

 

Value of common units issued in business combinations

 

$

80,619

 

$

2,224

 

$

80,619

 

$

433,668

 

 

Cash flows from commodity derivative instruments are classified as cash flows from investing activities in the consolidated statements of cash flows.

 

Inventories

 

Inventories consist of the following:

 

 

 

September 30,

 

March 31,

 

 

 

2013

 

2013

 

 

 

(in thousands)

 

Crude oil

 

$

56,514

 

$

46,156

 

Propane

 

207,511

 

45,428

 

Butane

 

62,852

 

23,106

 

Other natural gas liquids

 

14,947

 

984

 

Other

 

13,476

 

11,221

 

 

 

$

355,300

 

$

126,895

 

 

Accrued Expenses and Other Payables

 

Accrued expenses and other payables consist of the following:

 

 

 

September 30,

 

March 31,

 

 

 

2013

 

2013

 

 

 

(in thousands)

 

 

 

 

 

 

 

Product exchange liabilities

 

$

42,232

 

$

6,741

 

Income and other tax liabilities

 

22,230

 

22,659

 

Accrued compensation and benefits

 

14,885

 

27,252

 

Other

 

22,641

 

29,051

 

 

 

$

101,988

 

$

85,703

 

 

11



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Business Combination Measurement Period

 

We record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Pursuant to GAAP, an entity is allowed a reasonable period of time to obtain the information necessary to identify and measure the value of the assets acquired and liabilities assumed in a business combination. As described in Note 3, certain of our acquisitions during the fiscal year ended March 31, 2013 and during the six months ended September 30, 2013 are still within this measurement period, and as a result, the acquisition date values we have recorded for the acquired assets and assumed liabilities are subject to change.

 

Also as described in Note 3, we made certain adjustments during the six months ended September 30, 2013 to our estimates of the acquisition date fair values of assets acquired and liabilities assumed in certain business combinations that occurred during the fiscal year ended March 31, 2013. Due to the immateriality of these adjustments, we did not retroactively adjust the consolidated balance sheet at March 31, 2013 or the consolidated statements of operations for periods during the year ended March 31, 2013 for these measurement period adjustments.

 

Note 3 — Acquisitions

 

Fiscal Year Ending March 31, 2014

 

Oilfield Water Lines, LP

 

On August 2, 2013, we completed a business combination with OWL, whereby we acquired water disposal and transportation assets in Texas. We issued 2,463,287 common units, valued at $68.6 million, and paid $167.7 million of cash, net of cash acquired, in exchange for OWL. The acquisition agreements also contemplate a post-closing payment for certain working capital items. The acquisition agreements also include a provision whereby the purchase price may be increased if certain performance targets are achieved. If the acquired assets generate Adjusted EBITDA, as defined in the acquisition agreements, in excess of $3.3 million during any one of the six months following the acquisition, the purchase price will be increased by seventy-two times the amount by which this target is exceeded. The maximum potential increase to the purchase price under this provision is $60 million. We incurred and charged to general and administrative expense during the six months ended September 30, 2013 approximately $0.7 million of costs related to the OWL acquisition.

 

We are in the process of identifying and determining the fair value of the assets and liabilities acquired in the acquisition of OWL. The estimates of fair value reflected as of September 30, 2013 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

 

Accounts receivable - trade

 

$

8,550

 

Inventories

 

154

 

Other current assets

 

382

 

Property, plant and equipment:

 

 

 

Land

 

710

 

Water treatment facilities and equipment (3-30 years)

 

24,495

 

Vehicles (5-10 years)

 

8,254

 

Buildings and leasehold improvements (7-30 years)

 

740

 

Other (3-5 years)

 

264

 

Intangible assets:

 

 

 

Customer relationships (10 years)

 

56,000

 

Goodwill

 

145,558

 

Trade accounts payable

 

(6,063

)

Accrued expenses

 

(2,691

)

Other noncurrent liabilities

 

(64

)

Fair value of net assets acquired

 

$

236,289

 

 

12



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Consideration paid consists of the following (in thousands):

 

Cash paid, net of cash acquired

 

$

167,720

 

Value of common units issued

 

68,569

 

Total consideration paid

 

$

236,289

 

 

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses 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.

 

As described above, the agreements with the former owners of OWL contain a provision whereby the purchase price may be increased if the business meets a specified performance target during the six months subsequent to the acquisition. In order to determine an estimate of the fair value of this contingent consideration at the acquisition date, we identified the variables most likely to impact this performance target. Using historical and projected data, we prepared a Monte-Carlo type simulation and applied an option pricing model. We concluded that the fair value of the contingent consideration approximated zero, and as a result, we did not record a liability at the acquisition date for the contingent consideration. We performed a similar calculation at September 30, 2013, and concluded that the fair value of the contingent consideration continued to approximate zero at September 30, 2013. We will evaluate the fair value of the contingent consideration again at December 31, 2013, and if we conclude that the contingent consideration has a fair value at that date, we will record a liability and a corresponding expense during the three months ending December 31, 2013.

 

The operations of OWL have been included in our consolidated statement of operations since OWL was acquired on August 2, 2013. Our consolidated statements of operations for the three months and six months ended September 30, 2013 include revenues of $7.3 million and operating income of $0.5 million that was generated by the operations of OWL. The following unaudited pro forma consolidated data below is presented for the six months ended September 30, 2013 as if the OWL acquisition had been completed on April 1, 2013 (in thousands, except per unit amounts). The pro forma earnings per unit are based on the common and subordinated units outstanding as of September 30, 2013.

 

Revenues

 

$

2,991,936

 

 

 

 

 

 

 

Net loss

 

(17,482

)

 

 

 

 

 

 

Limited partners’ interest in net loss

 

(21,755

)

 

 

 

 

 

 

Basic and diluted loss per common unit

 

(0.31

)

 

 

 

 

 

 

Basic and diluted loss per subordinated unit

 

(0.31

)

 

 

 

 

 

 

 

The pro forma consolidated data in the table above was prepared by adding the historical results of operations of OWL to our historical results of operations and making certain pro forma adjustments. The pro forma adjustments include: (i) replacing the historical depreciation and amortization expense of OWL with pro forma depreciation and amortization expense, calculated using the estimated fair values of long-lived assets recorded in the acquisition accounting; (ii) replacing the historical interest expense of OWL with pro forma interest expense; and (iii) excluding professional fees and other expenses incurred by us that were directly related to the acquisition. In order to calculate pro forma earnings per unit in the table above, we assumed that: (i) the same number of limited partner units outstanding at September 30, 2013 had been outstanding throughout the period shown in the table, and (ii) all of the common units were eligible for distributions related to the period shown in the table. The pro forma information is not necessarily indicative of the results of operations that would have occurred if the acquisition had been completed on April 1, 2013, nor is it necessarily indicative of the future results of the combined operations. We have not presented pro forma data for periods during the prior fiscal year, as certain of the assets we acquired in the acquisition of OWL had not yet been developed as of September 30, 2012.

 

Other Water Services Acquisitions

 

During the three months ended September 30, 2013, we completed two separate acquisitions of businesses to expand our water services operations in Texas. On a combined basis, we issued 222,381 common units, valued at $6.8 million, and paid $151.5 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. The agreements for the

 

13



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

acquisitions of these businesses contemplate post-closing payments for certain working capital items. We incurred and charged to general and administrative expense during the six months ended September 30, 2013 approximately $0.3 million of costs related to these acquisitions.

 

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these two business combinations. The estimates of fair value reflected as of September 30, 2013 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

 

Accounts receivable - trade

 

$

1,959

 

Inventories

 

192

 

Other current assets

 

112

 

Property, plant and equipment:

 

 

 

Land

 

206

 

Vehicles (5-10 years)

 

90

 

Water treatment facilities and equipment (3-30 years)

 

15,683

 

Buildings and leasehold improvements (7-30 years)

 

616

 

Other (3-5 years)

 

12

 

Intangible assets:

 

 

 

Customer relationships (5-10 years)

 

36,500

 

Trade names (indefinite life)

 

2,800

 

Non-compete agreements (3 years)

 

260

 

Development agreement (5 years)

 

14,000

 

Option agreement

 

2,500

 

Goodwill

 

83,813

 

Trade accounts payable

 

(82

)

Accrued expenses

 

(273

)

Other noncurrent liabilities

 

(64

)

Fair value of net assets acquired

 

$

158,324

 

 

Consideration paid consists of the following (in thousands):

 

Cash paid, net of cash acquired

 

$

151,530

 

Value of common units issued

 

6,794

 

Total consideration paid

 

$

158,324

 

 

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses 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.

 

As part of one of these business combinations, we entered into a development agreement with the seller of the business. Under this agreement, we have the option to purchase water treatment facilities that are developed by the other party to the agreement during the five years following the business combination. We recorded an intangible asset of $14.0 million at the acquisition date related to this development agreement.

 

As part of the other business combination, we entered into an option agreement with the seller of the business whereby we have the option to purchase a water treatment facility that is currently under construction. We recorded an intangible asset of $2.5 million at the acquisition date related to this option agreement.

 

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Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Crude Oil Logistics Acquisitions

 

During the three months ended September 30, 2013, we completed two separate acquisitions of businesses to expand our crude oil logistics business in Texas and Oklahoma. On a combined basis, we issued 175,211 common units, valued at $5.3 million, and paid $67.8 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. The agreement for the acquisition of one of these businesses contemplates a post-closing payment for certain working capital items. We incurred and charged to general and administrative expense during the six months ended September 30, 2013 approximately $0.2 million of costs related to these acquisitions.

 

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these two business combinations. The estimates of fair value reflected as of September 30, 2013 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the three months ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

 

Accounts receivable - trade

 

$

1,233

 

Inventories

 

1,021

 

Property, plant and equipment:

 

 

 

Vehicles (5-10 years)

 

2,709

 

Buildings and leasehold improvements (5-30 years)

 

260

 

Crude oil tanks and related equipment (2-30 years)

 

3,580

 

Barges and tow boats (20 years)

 

11,996

 

Other (3-5 years)

 

42

 

Intangible assets:

 

 

 

Customer relationships (3 years)

 

1,700

 

Trade names (indefinite life)

 

530

 

Goodwill

 

50,856

 

Trade accounts payable

 

(660

)

Accrued expenses

 

(124

)

Other noncurrent liabilities

 

(53

)

Fair value of net assets acquired

 

$

73,090

 

 

Consideration paid consists of the following (in thousands):

 

Cash paid, net of cash acquired

 

$

67,834

 

Value of common units issued

 

5,256

 

Total consideration paid

 

$

73,090

 

 

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses 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.

 

Retail Propane Acquisitions

 

During the six months ended September 30, 2013, we completed three acquisitions of retail propane businesses. On a combined basis, we paid $5.9 million of cash to acquire these assets and operations. The agreements for the acquisitions of these businesses contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these three business combinations, and as a result the estimates of fair value reflected as of September 30, 2013 are subject to change. We expect to complete this process prior to finalizing our financial statements for the fiscal year ending March 31, 2014.

 

15



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Fiscal Year Ended March 31, 2013

 

Pecos Combination

 

On November 1, 2012, we completed a business combination whereby we acquired Pecos. The business of Pecos consists primarily of crude oil marketing and logistics operations in Texas and New Mexico. We paid $132.4 million of cash (net of cash acquired) and assumed certain obligations with a value of $10.2 million under certain equipment financing facilities. Also on November 1, 2012, we entered into a call agreement with the former owners of Pecos pursuant to which the former owners of Pecos agreed to purchase a minimum of $45.0 million or a maximum of $60.0 million of common units from us. On November 12, 2012, the former owners purchased 1,834,414 common units from us for $45.0 million pursuant to this call agreement.

 

During the three months ended September 30, 2013, we completed the acquisition accounting for this business combination. The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of Pecos (in thousands):

 

 

 

 

 

Estimated

 

 

 

 

 

 

 

as of

 

 

 

 

 

 

 

March 31,

 

 

 

 

 

Final

 

2013

 

Difference

 

 

 

 

 

 

 

 

 

Accounts receivable - trade

 

$

73,609

 

$

73,704

 

$

(95

)

Inventories

 

1,903

 

1,903

 

 

Other current assets

 

1,426

 

1,426

 

 

Property, plant and equipment:

 

 

 

 

 

 

 

Vehicles (5-10 years)

 

22,097

 

19,193

 

2,904

 

Buildings and leasehold improvements (5-30 years)

 

1,339

 

1,248

 

91

 

Crude oil tanks and related equipment (2-15 years)

 

1,099

 

913

 

186

 

Land

 

223

 

224

 

(1

)

Other (3-5 years)

 

36

 

177

 

(141

)

Intangible assets:

 

 

 

 

 

 

 

Customer relationships

 

 

8,000

 

(8,000

)

Trade names (indefinite life)

 

900

 

1,000

 

(100

)

Goodwill

 

91,747

 

86,661

 

5,086

 

Trade accounts payable

 

(50,795

)

(50,808

)

13

 

Accrued expenses

 

(963

)

(1,020

)

57

 

Long-term debt

 

(10,234

)

(10,234

)

 

Fair value of net assets acquired

 

$

132,387

 

$

132,387

 

$

 

 

Consideration paid consists of the following (in thousands):

 

Cash paid, net of cash acquired

 

$

87,444

 

Value of common units issued

 

44,943

 

Total consideration paid

 

$

132,387

 

 

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses 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.

 

16



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Third Coast Combination

 

On December 31, 2012, we completed a business combination transaction whereby we acquired all of the membership interests in Third Coast for $43.0 million in cash. The business of Third Coast consists primarily of transporting crude oil via barge. Also on December 31, 2012, we entered into a call agreement with the former owners of Third Coast pursuant to which the former owners of Third Coast agreed to purchase a minimum of $8.0 million or a maximum of $10.0 million of common units from us. On January 11, 2013, the former owners of Third Coast purchased 344,680 common units from us for $8.0 million pursuant to this agreement.

 

We are in the process of identifying and determining the fair value of the assets and liabilities acquired in the acquisition of Third Coast. The estimates of fair value reflected as of September 30, 2013 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the three months ending December 31, 2013. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

 

 

 

Estimated As of

 

 

 

 

 

September 30,

 

March 31,

 

 

 

 

 

2013

 

2013

 

Difference

 

 

 

 

 

 

 

 

 

Accounts receivable - trade

 

$

2,195

 

$

2,248

 

$

(53

)

Inventories

 

140

 

140

 

 

Property, plant and equipment:

 

 

 

 

 

 

 

Barges and tow boats (20 years)

 

12,883

 

12,883

 

 

Other (3-7 years)

 

30

 

30

 

 

Intangible assets:

 

 

 

 

 

 

 

Customer relationships (3 years)

 

3,000

 

4,000

 

(1,000

)

Trade names (indefinite life)

 

850

 

500

 

350

 

Goodwill

 

23,645

 

22,551

 

1,094

 

Other noncurrent assets

 

2,733

 

2,733

 

 

Trade accounts payable

 

(2,429

)

(2,048

)

(381

)

Accrued expenses

 

(164

)

(154

)

(10

)

Fair value of net assets acquired

 

$

42,883

 

$

42,883

 

$

 

 

Consideration paid consists of the following (in thousands):

 

Cash paid, net of cash acquired

 

$

35,000

 

Value of common units issued

 

7,883

 

Total consideration paid

 

$

42,883

 

 

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses 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.

 

Other Crude Oil Logistics and Water Services Business Combinations

 

During the year ended March 31, 2013, we completed four separate acquisitions to expand the assets and operations of our crude oil logistics and water services businesses. On a combined basis, we paid $52.6 million in cash and assumed $1.3 million of long-term debt in the form of non-compete agreements. We also issued 516,978 common units, valued at $12.4 million, as partial consideration for one of these acquisitions.

 

During the three months ended September 30, 2013, we completed the acquisition accounting for these business combinations. The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of these businesses (in thousands):

 

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

 

 

 

 

Estimated

 

 

 

 

 

 

 

as of

 

 

 

 

 

 

 

March 31,

 

 

 

 

 

Final

 

2013

 

Difference

 

 

 

 

 

 

 

 

 

Accounts receivable - trade

 

$

2,676

 

$

2,660

 

$

16

 

Inventories

 

191

 

191

 

 

Other current assets

 

737

 

738

 

(1

)

Property, plant and equipment:

 

 

 

 

 

 

 

Land

 

218

 

191

 

27

 

Vehicles (5-10 years)

 

853

 

771

 

82

 

Water treatment facilities and related equipment (3-30 years)

 

13,665

 

13,322

 

343

 

Buildings and leasehold improvements (5-30 years)

 

895

 

2,233

 

(1,338

)

Crude oil tanks and related equipment (2-15 years)

 

4,510

 

1,781

 

2,729

 

Other (3-5 years)

 

27

 

2

 

25

 

Construction in progress

 

490

 

693

 

(203

)

Intangible assets:

 

 

 

 

 

 

 

Customer relationships (5-10 years)

 

13,125

 

6,800

 

6,325

 

Non-compete agreements (3 years)

 

164

 

510

 

(346

)

Trade names (indefinite life)

 

2,100

 

500

 

1,600

 

Goodwill

 

34,451

 

43,822

 

(9,371

)

Trade accounts payable

 

(3,374

)

(3,374

)

 

Accrued expenses

 

(1,914

)

(2,026

)

112

 

Long-term debt

 

(1,340

)

(1,340

)

 

Other noncurrent liabilities

 

(156

)

(156

)

 

Noncontrolling interest

 

(2,333

)

(2,333

)

 

Fair value of net assets acquired

 

$

64,985

 

$

64,985

 

$

 

 

Consideration paid consists of the following (in thousands):

 

Cash paid, net of cash acquired

 

$

52,552

 

Value of common units issued

 

12,433

 

Total consideration paid

 

$

64,985

 

 

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses 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 fair value of the customer relationship intangible assets 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

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Note 4 — Earnings per Unit

 

Our earnings per common and subordinated unit for the periods indicated below were computed as follows:

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(in thousands, except unit and per unit amounts)

 

Basic and diluted earnings (loss) per common or subordinated unit

 

 

 

 

 

 

 

 

 

Income (loss) attributable to parent equity

 

$

(941

)

$

10,073

 

$

(18,574

)

$

(14,577

)

Income allocated to general partner(*)

 

(2,451

)

(694

)

(4,139

)

(789

)

Income (loss) allocated to limited partners

 

$

(3,392

)

$

9,379

 

$

(22,713

)

$

(15,366

)

 

 

 

 

 

 

 

 

 

 

Income (loss) allocated to:

 

 

 

 

 

 

 

 

 

Common unitholders

 

$

(2,830

)

$

8,286

 

$

(19,637

)

$

(13,112

)

Subordinated unitholders

 

$

(562

)

$

1,093

 

$

(3,076

)

$

(2,254

)

 

 

 

 

 

 

 

 

 

 

Weighted average common units outstanding

 

58,909,389

 

44,831,836

 

53,336,969

 

35,730,492

 

 

 

 

 

 

 

 

 

 

 

Weighted average subordinated units outstanding

 

5,919,346

 

5,919,346

 

5,919,346

 

5,919,346

 

 

 

 

 

 

 

 

 

 

 

Income (loss) per common unit - basic and diluted

 

$

(0.05

)

$

0.18

 

$

(0.37

)

$

(0.37

)

 

 

 

 

 

 

 

 

 

 

Income (loss) per subordinated unit - basic and diluted

 

$

(0.09

)

$

0.18

 

$

(0.52

)

$

(0.38

)

 


(*)         The 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 10.

 

The restricted units described in Note 10 were antidilutive for the three-month and six-month periods ended September 30, 2013 and 2012.

 

19



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Note 5 — Property, Plant and Equipment

 

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

 

 

 

September 30,

 

March 31,

 

Description and Useful Life

 

2013

 

2013

 

 

 

(in thousands)

 

Natural gas liquids terminal assets (30 years)

 

$

64,586

 

$

63,637

 

Retail propane equipment (5-20 years)

 

157,534

 

152,802

 

Vehicles (5-10 years)

 

108,280

 

85,200

 

Water treatment facilities and equipment (3-30 years)

 

150,632

 

91,601

 

Crude oil tanks and related equipment (2-30 years)

 

27,384

 

21,308

 

Barges and tow boats (20 years)

 

33,957

 

21,135

 

Information technology equipment (3-5 years)

 

15,223

 

12,169

 

Buildings and leasehold improvements (5-30 years)

 

45,108

 

48,394

 

Land

 

22,994

 

21,604

 

Other (3-10 years)

 

17,673

 

17,288

 

Construction in progress

 

64,682

 

31,926

 

 

 

708,053

 

567,064

 

Less: Accumulated depreciation

 

(76,390

)

(50,127

)

Net property, plant and equipment

 

$

631,663

 

$

516,937

 

 

Depreciation expense was $13.7 million and $7.7 million for the three months ended September 30, 2013 and 2012, respectively, and $27.2 million and $13.8 million for the six months ended September 30, 2013 and 2012, respectively.

 

Note 6 — Goodwill and Intangible Assets

 

The changes in the balance of goodwill during the six months ended September 30, 2013 were as follows (in thousands):

 

Balance at March 31, 2013

 

$

563,146

 

Revisions to acquisition accounting (Note 3)

 

(3,191

)

Acquisitions

 

280,332

 

Balance at September 30, 2013

 

$

840,287

 

 

Goodwill by reportable segment is as follows:

 

 

 

September 30,

 

March 31,

 

 

 

2013

 

2013

 

 

 

(in thousands)

 

Crude oil logistics

 

$

302,000

 

$

244,073

 

Water services

 

338,842

 

119,668

 

Natural gas liquids logistics

 

87,136

 

87,136

 

Retail propane

 

112,309

 

112,269

 

 

 

$

840,287

 

$

563,146

 

 

20



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

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

 

 

 

 

 

September 30, 2013

 

March 31, 2013

 

 

 

 

 

Gross Carrying

 

Accumulated

 

Gross Carrying

 

Accumulated

 

 

 

Useful Lives

 

Amount

 

Amortization

 

Amount

 

Amortization

 

 

 

 

 

(in thousands)

 

Amortizable —

 

 

 

 

 

 

 

 

 

 

 

Customer relationships*

 

3-20 years

 

$

500,546

 

$

49,475

 

$

407,835

 

$

30,959

 

Water facility development agreement

 

5 years

 

14,000

 

467

 

 

 

Lease and other agreements

 

1-8 years

 

15,210

 

8,591

 

15,210

 

7,018

 

Non-compete agreements

 

2-7 years

 

11,984

 

4,338

 

11,855

 

2,871

 

Trade names

 

3-10 years

 

2,784

 

476

 

2,784

 

326

 

Debt issuance costs

 

5-10 years

 

21,712

 

5,443

 

19,494

 

2,981

 

Total amortizable

 

 

 

566,236

 

68,790

 

457,178

 

44,155

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-amortizable

 

 

 

 

 

 

 

 

 

 

 

Trade names

 

 

 

34,800

 

 

29,580

 

 

Water facility option agreement

 

 

 

2,500

 

 

 

 

Total

 

 

 

$

603,536

 

$

68,790

 

$

486,758

 

$

44,155

 

 


*                 The weighted-average remaining amortization period for customer relationship intangible assets is approximately 10 years.

 

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

 

Year Ending March 31,

 

 

 

2014 (six months)

 

$

29,465

 

2015

 

56,816

 

2016

 

54,777

 

2017

 

51,762

 

2018

 

45,891

 

Thereafter

 

258,735

 

 

 

$

497,446

 

 

Amortization expense was as follows:

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

September 30,

 

September 30,

 

Recorded in

 

2013

 

2012

 

2013

 

2012

 

 

 

(in thousands)

 

Depreciation and amortization

 

$

11,324

 

$

5,654

 

$

20,600

 

$

8,820

 

Cost of sales

 

949

 

1,352

 

1,574

 

1,552

 

Interest expense

 

1,065

 

835

 

2,462

 

1,336

 

Loss on early extinguishment of debt

 

 

 

 

5,769

 

 

 

$

13,338

 

$

7,841

 

$

24,636

 

$

17,477

 

 

21



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Note 7 — Long-Term Debt

 

Our long-term debt consists of the following:

 

 

 

September 30,

 

March 31,

 

 

 

2013

 

2013

 

 

 

(in thousands)

 

Revolving credit facility —

 

 

 

 

 

Expansion capital loans

 

$

416,500

 

$

441,500

 

Working capital loans

 

229,500

 

36,000

 

 

 

 

 

 

 

Senior notes

 

250,000

 

250,000

 

 

 

 

 

 

 

Other notes payable

 

18,295

 

21,562

 

 

 

914,295

 

749,062

 

Less - current maturities

 

8,229

 

8,626

 

Long-term debt

 

$

906,066

 

$

740,436

 

 

Credit Agreement

 

On June 19, 2012, we 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”).

 

The Working Capital Facility had a total capacity of $325.0 million for cash borrowings and letters of credit at September 30, 2013. At September 30, 2013, we had outstanding cash borrowings of $229.5 million and outstanding letters of credit of $85.9 million on the Working Capital Facility, leaving a remaining capacity of $9.6 million at September 30, 2013. The Expansion Capital Facility had a total capacity of $725.0 million for cash borrowings at September 30, 2013. At September 30, 2013, we had outstanding cash borrowings of $416.5 million on the Expansion Capital Facility, leaving a remaining capacity of $308.5 million at September 30, 2013. The capacity available under the Working Capital Facility may be limited by a “borrowing base,” as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time. At September 30, 2013, the borrowing base provisions of the Credit Agreement did not have any impact on the capacity available under the Working Capital Facility.

 

The commitments under the Credit Agreement expire on June 19, 2017. We have the right to pre-pay outstanding borrowings under the Credit Agreement without incurring any penalties, and pre-payments of principal may be required if we enter into certain transactions to sell assets or obtain new borrowings.

 

22



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 1.75% to 2.75% per annum or (ii) an adjusted LIBOR rate plus a margin of 2.75% to 3.75% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At September 30, 2013, the interest rate in effect on outstanding LIBOR borrowings was 3.19%, calculated as the LIBOR rate of 0.19% plus a margin of 3.0%. At September 30, 2013, the interest rate in effect on outstanding base rate borrowings was 5.25%, calculated as the base rate of 3.25% plus a margin of 2.0%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. At September 30, 2013, our outstanding borrowings and interest rates under our Revolving Credit Facility were as follows (dollars in thousands):

 

 

 

Amount

 

Rate

 

Expansion Capital Facility —

 

 

 

 

 

LIBOR borrowings

 

$

416,500

 

3.19

%

Working Capital Facility —

 

 

 

 

 

LIBOR borrowings

 

204,000

 

3.18

%

Base rate borrowings

 

25,500

 

5.25

%

 

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 1.0 at any quarter end. At September 30, 2013, our leverage ratio was less than 2.5 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 as of the last day of any fiscal quarter. At September 30, 2013, our interest coverage ratio was greater than 7.5 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, 2013, we were in compliance with all covenants under the Credit Agreement.

 

As described in Note 14, we entered into an amendment to the Credit Agreement during November 2013. This amendment increased the capacity on the Expansion Capital and Working Capital facilities, extended the maturity date of the Credit Agreement, and reduced the interest rate on LIBOR rate borrowings.

 

Senior Notes

 

On June 19, 2012, we entered into a note purchase agreement (the “Note Purchase Agreement”) whereby we issued $250 million of Senior Notes in a private placement (the “Senior Notes”). The Senior Notes have an aggregate principal amount of $250.0 million and bear interest at a fixed rate of 6.65%. Interest is payable quarterly. The Senior 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 pre-pay outstanding principal, although we would incur a pre-payment penalty. The Senior 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 or merge or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains the same leverage ratio and interest coverage ratio requirements as our Credit Agreement, which are 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) non-payment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the Senior Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10 million, (iv) the rendering of a judgment for the payment of money in excess of $10 million, (v) the failure of the Note Purchase Agreement, the Senior 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 Senior Notes of any series may declare all of the Senior Notes of such series to be due and payable immediately.

 

At September 30, 2013, we were in compliance with all covenants under the Note Purchase Agreement and the Senior Notes.

 

23



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Senior Unsecured Notes

 

As described in Note 14, we issued $450.0 million of senior unsecured notes during October 2013. These senior unsecured notes bear interest at a fixed rate of 6.875% and mature on October 15, 2021.

 

Other Notes Payable

 

We have executed various non-interest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also have certain notes payable that relate to equipment financing, which have interest rates ranging from 2.1% to 4.9% at September 30, 2013.

 

Debt Maturity Schedule

 

The scheduled maturities of our long-term debt are as follows as of September 30, 2013 (in thousands):

 

 

 

Revolving

 

 

 

Other

 

 

 

 

 

Credit

 

Senior

 

Notes

 

 

 

Year Ending March 31,

 

Facility

 

Notes

 

Payable

 

Total

 

2014 (six months)

 

$

 

$

 

$

5,780

 

$

5,780

 

2015

 

 

 

6,913

 

6,913

 

2016

 

 

 

3,186

 

3,186

 

2017

 

 

 

1,888

 

1,888

 

2018

 

646,000

 

25,000

 

328

 

671,328

 

Thereafter

 

 

225,000

 

200

 

225,200

 

 

 

$

646,000

 

$

250,000

 

$

18,295

 

$

914,295

 

 

Previous Credit Facilities

 

On June 19, 2012, we made a principal payment of $306.8 million to retire our previous revolving credit facility. Upon retirement of this facility, we wrote off the portion of the debt issuance cost asset that had not yet been amortized. This expense is reported as “Loss on early extinguishment of debt” in our consolidated statement of operations.

 

Note 8 — Income Taxes

 

We believe that we qualify as a partnership for income tax purposes. As such, we generally do not pay U.S. federal income tax. Rather, each owner reports his or her share of our income or loss on his or her individual tax return. The aggregate difference in

 

24



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

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 two taxable corporate subsidiaries in the United States and three taxable corporate subsidiaries in Canada. The income tax provision reported in our consolidated statements of operations relates primarily to these subsidiaries.

 

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 both 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 the consolidated financial statements at September 30, 2013.

 

Note 9 — Commitments and Contingencies

 

Legal Contingencies

 

We are party to various claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of our management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, will not 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.

 

Customer Dispute

 

A customer of our crude oil logistics segment has disputed the transportation rate schedule we used to bill the customer for services that we provided from November 2012 through February 2013, which was the same rate schedule that Pecos used to bill the customer from April 2011 through October 2012 (prior to our acquisition of Pecos). The customer has not paid $1.7 million of the amount we charged for services we provided from November 2012 through February 2013. In May 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. Later in May 2013, the customer filed an answer and counterclaim seeking to recover $5.5 million that it paid to Pecos prior to our acquisition of Pecos. We have not recorded revenue for the $1.7 million of unpaid fees charged from November 2012 through February 2013, pending resolution of the dispute. During August 2013, the customer notified us that it intended to withhold payment of approximately $3.3 million for services performed by us during the period from June 2013 through August 2013, pending resolution of the dispute, although the customer has not disputed the validity of the amounts billed for services performed during this time frame. Upon receiving this notification, we ceased providing services under this contract, and on November 5, 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. We are not able to reliably predict the outcome of this dispute at this time, but we do not believe the outcome will have a material adverse effect on our consolidated financial position or results of operations.

 

Canadian Fuel and Sales Taxes

 

The taxing authority of a province in Canada completed an audit of fuel and sales tax payments and concluded that High Sierra should have collected from customers and remitted to the taxing authority approximately $14.9 million of fuel taxes and sales taxes on certain historical sales. High Sierra had not collected and remitted fuel and sales taxes on these transactions, as High Sierra believed the transactions were exempt from these taxes. We are in the process of gathering information to support our position that the transactions were exempt from the taxes, which we believe could substantially reduce the amount of the tax that would be assessed. If we are unsuccessful in demonstrating that these transactions were exempt and if these taxes are ultimately assessed, we would be required to remit payment to the taxing authority; however, we expect we would be able to recover these payments from the customers pursuant to the terms of our contracts with the customers. Although the outcome of this matter is not certain at this time, we do not believe the ultimate resolution of this matter will have a material adverse effect on our consolidated financial position or results of operations. We recorded in the acquisition accounting for the merger with High Sierra a liability of $14.9 million, which is the full amount identified during the audit, and a receivable of $14.1 million, which represents the amount we would expect to recover from the customers in the event we are ultimately required to pay the amount identified during the audit.

 

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Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

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 significant costs will not be incurred. 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

 

We have recorded an asset retirement obligation liability of $1.8 million at September 30, 2013. This liability is related to the wastewater disposal assets and crude oil pipeline injection facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

 

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

 

Operating Leases

 

We have executed various non-cancelable operating lease agreements for product storage, office space, vehicles, real estate, and equipment. Future minimum lease payments under contractual commitments as of September 30, 2013 are as follows (in thousands):

 

Year Ending March 31,

 

 

 

2014 (six months)

 

$

31,924

 

2015

 

51,652

 

2016

 

46,720

 

2017

 

44,174

 

2018

 

36,636

 

Thereafter

 

80,402

 

Total

 

$

291,508

 

 

Rental expense relating to operating leases was $17.0 million during the three months ended September 30, 2013 and $12.5 million during the three months ended September 30, 2012. Rental expense relating to operating leases was $32.5 million during the six months ended September 30, 2013 and $17.2 million during the six months ended September 30, 2012.

 

26



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Sales and Purchase Contracts

 

We have entered into sales and purchase contracts for natural gas liquids (including propane, butane, and ethane) and crude oil to be delivered in future periods. These contracts require that the parties physically settle the transactions with inventory. At September 30, 2013, we had the following such commitments outstanding:

 

 

 

Volume

 

Value

 

 

 

(in thousands)

 

Natural gas liquids fixed-price purchase commitments (gallons)

 

79,041

 

$

74,356

 

Natural gas liquids floating-price purchase commitments (gallons)

 

653,808

 

722,942

 

Natural gas liquids fixed-price sale commitments (gallons)

 

146,432

 

183,717

 

Natural gas liquids floating-price sale commitments (gallons)

 

464,196

 

561,382

 

 

 

 

 

 

 

Crude oil floating-price purchase commitments (barrels)

 

4,963

 

509,734

 

Crude oil floating-price sale commitments (barrels)

 

4,584

 

522,787

 

 

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.

 

Certain of the forward purchase and sale contracts shown in the table above were acquired in the June 2012 merger with High Sierra. We recorded these contracts at their estimated fair values at the merger date, and we are amortizing these assets and liabilities to cost of sales over the remaining terms of the contracts. We recorded the following expense (benefit) to cost of sales related to the amortization of the assets and liabilities related to these contracts (in thousands):

 

 

 

Natural Gas

 

Crude Oil

 

 

 

 

 

Liquids Logistics

 

Logistics

 

 

 

For the Six Months Ended:

 

Segment

 

Segment

 

Total

 

September 30, 2013

 

$

2,420

 

$

(164

)

$

2,256

 

September 30, 2012

 

2,742

 

(464

)

2,278

 

 

At September 30, 2013, the net unamortized balance included in our consolidated balance sheet is a net asset of $0.3 million, which we will amortize to cost of sales during the third and fourth quarters of the fiscal year ending March 31, 2014.

 

Note 10 — Equity

 

Partnership Equity

 

The Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest. Limited partner equity includes common and subordinated units. The common and subordinated units share equally in the allocation of income or loss. The principal difference between common and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

 

The subordination period will end on the first business day after we have earned and paid the minimum quarterly distribution on each outstanding common unit and subordinated unit and the corresponding distribution on the general partner interest for each of three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2014. The subordination period will terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of removal. When

 

27



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

the subordination period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages.

 

Our general partner is not obligated to make any additional capital contributions or to guarantee or pay any of our debts and obligations.

 

Distributions

 

Our general partner has adopted a cash distribution policy that will require us to pay a quarterly distribution to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner and its affiliates, referred to as “available cash,” in the following manner:

 

·                  First, 99.9% to the holders of common units and 0.1% to the general partner, until each common unit has received the specified minimum quarterly distribution, plus any arrearages from prior quarters.

 

·                  Second, 99.9% to the holders of subordinated units and 0.1% to the general partner, until each subordinated unit has received the specified minimum quarterly distribution.

 

·                  Third, 99.9% to all unitholders, pro rata, and 0.1% to the general partner.

 

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.”

 

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders 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 the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit.” The percentage interests shown for our unitholders 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, assume our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and has not transferred its incentive distribution rights and there are no arrearages on common units.

 

 

 

 

 

Marginal Percentage Interest In

 

 

 

Total Quarterly

 

Distributions

 

 

 

Distribution Per Unit

 

Unitholders

 

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

%

 

During the three months ended September 30, 2013, we distributed a total of $33.5 million ($0.49375 per common and subordinated limited partner unit and per general partner notional unit) to our unitholders of record as of August 5, 2013. This included an incentive distribution of $1.7 million to the general partner. On October 23, 2013, we declared a distribution of $0.51125 per common unit, to be paid on November 14, 2013 to unitholders of record on November 4, 2013. This distribution amounts to $38.4 million, including amounts to be paid on common, subordinated, and general partner notional units and the amount to be paid on incentive distribution rights.

 

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Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Equity Offerings

 

On July 5, 2013, we completed a public offering of 10,350,000 common units. We received net proceeds of approximately $287.5 million, after underwriting discounts and commissions of $12.0 million and offering costs of $0.7 million. We used the net proceeds from the offering to reduce the outstanding balance on our Revolving Credit Facility.

 

On September 25, 2013, we completed a public offering of 4,100,000 common units. We received net proceeds of $127.6 million, after underwriting discounts and commissions of $5.0 million and offering costs of $0.2 million. We used the net proceeds from the offering to reduce the outstanding balance on our Revolving Credit Facility.

 

Equity-Based Incentive Compensation

 

Our general partner has adopted a long-term incentive plan (the “LTIP”), which allows for the issuance of equity-based compensation to employees and directors. During the fiscal year ended March 31, 2013 and during the six months ended September 30, 2013, the board of directors of our general partner granted certain restricted units to employees and directors, which will 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 will accrue to or be paid on the restricted units during the vesting period.

 

The following table summarizes the restricted unit activity during the six months ended September 30, 2013:

 

Unvested restricted units at March 31, 2013

 

1,444,900

 

Units granted

 

323,000

 

Units vested and issued

 

(282,692

)

Units withheld for employee taxes

 

(116,108

)

Units forfeited

 

(15,000

)

Unvested restricted units at September 30, 2013

 

1,354,100

 

 

The scheduled vesting of the awards is summarized below:

 

Vesting Date

 

Number of Awards

 

January 1, 2014

 

20,000

 

July 1, 2014

 

398,300

 

January 1, 2015

 

12,000

 

July 1, 2015

 

320,800

 

January 1, 2016

 

12,000

 

July 1, 2016

 

312,000

 

January 1, 2017

 

12,000

 

July 1, 2017

 

220,500

 

January 1, 2018

 

12,000

 

July 1, 2018

 

34,500

 

Total unvested units at September 30, 2013

 

1,354,100

 

 

On July 1, 2013, 398,800 of the awards vested. We issued 282,692 common units to the recipients and we recorded an increase to equity of $8.6 million. We withheld the remaining 116,108 common units, in return for which we paid $3.5 million of withholding taxes on behalf of the recipients.

 

29



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

We record the expense for each tranche on a straight-line basis over the period beginning with the vesting of the previous tranche and ending with the vesting of the tranche. We adjust the cumulative expense recorded through the reporting date using the estimated fair value of the awards at the reporting date. 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. The following table summarizes the expense we recorded related to the restricted unit awards during the periods indicated (in thousands):

 

For the Three Months Ended:

 

 

 

September 30, 2013

 

$

3,217

 

September 30, 2012

 

2,302

 

 

For the Six Months Ended:

 

 

 

September 30, 2013

 

$

10,292

 

September 30, 2012

 

2,957

 

 

We estimate that the future expense we will record on the unvested awards as of September 30, 2013 will be as follows (in thousands), after taking into consideration an estimate of forfeitures of approximately 77,000 units. For purposes of this calculation, we have used the closing price of the common units on September 30, 2013,which was $30.84.

 

Year Ending March 31,

 

 

 

2014 (six months)

 

$

6,404

 

2015

 

10,420

 

2016

 

9,407

 

2017

 

7,217

 

2018

 

2,515

 

2019

 

240

 

Total

 

$

36,203

 

 

Following is a rollforward of the liability related to equity-based compensation, which is reported within accrued expenses and other payables on our consolidated balance sheets (in thousands):

 

Balance at March 31, 2013

 

$

5,043

 

Expense recorded during the six months ended September 30, 2013

 

10,292

 

Value of units vested and issued

 

(8,619

)

Taxes paid on behalf of participants

 

(3,530

)

Balance at September 30, 2013

 

$

3,186

 

 

The weighted-average fair value of the awards at September 30, 2013 was $26.03, which was calculated as the closing price of the common units on September 30, 2013, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period.

 

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 and subordinated units. The maximum number of units deliverable under the plan automatically increases to 10% of the issued and outstanding common and subordinated 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 will not be considered to be delivered under the LTIP. In addition, if 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. As of September 30, 2013, approximately 5.3 million units remain available for issuance under the LTIP.

 

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Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Note 11 — Fair Value of Financial Instruments

 

Our cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, and other current liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values due to their short-term nature. We believe the carrying amounts of our long-term debt instruments, including the Revolving Credit Facility and the Senior Notes, approximate their fair values, as we do not believe market conditions have changed materially since we entered into these debt agreements.

 

Commodity Derivatives

 

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at September 30, 2013:

 

 

 

Derivative

 

Derivative

 

 

 

Assets

 

Liabilities

 

 

 

(in thousands)

 

Level 1 measurements

 

$

634

 

$

(2,747

)

Level 2 measurements

 

9,006

 

(15,551

)

 

 

9,640

 

(18,298

)

 

 

 

 

 

 

Netting of counterparty contracts (1)

 

(5,952

)

5,952

 

Cash collateral provided

 

 

2,745

 

Commodity contracts reported on consolidated balance sheet

 

$

3,688

 

$

(9,601

)

 


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

 

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2013:

 

 

 

Derivative

 

Derivative

 

 

 

Assets

 

Liabilities

 

 

 

(in thousands)

 

Level 1 measurements

 

$

947

 

$

(3,324

)

Level 2 measurements

 

9,911

 

(13,280

)

 

 

10,858

 

(16,604

)

 

 

 

 

 

 

Netting of counterparty contracts (1)

 

(3,503

)

3,503

 

Cash collateral provided or held

 

(1,760

)

400

 

Commodity contracts reported on consolidated balance sheet

 

$

5,595

 

$

(12,701

)

 


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

 

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Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

The commodity derivative assets (liabilities) are reported in the following accounts on the consolidated balance sheets:

 

 

 

September 30,

 

March 31,

 

 

 

2013

 

2013

 

 

 

(in thousands)

 

Prepaid expenses and other current assets

 

$

3,547

 

$

5,551

 

Other noncurrent assets

 

141

 

44

 

Accrued expenses and other payables

 

(9,154

)

(12,701

)

Other noncurrent liabilities

 

(447

)

 

Net liability

 

$

(5,913

)

$

(7,106

)

 

The following table sets forth our open commodity derivative contract positions at September 30, 2013 and March 31, 2013. We do not account for these derivatives as hedges.

 

 

 

 

 

Total

 

Fair Value

 

 

 

 

 

Notional

 

of

 

 

 

 

 

Units

 

Net Assets

 

Contracts

 

Settlement Period

 

(Barrels)

 

(Liabilities)

 

 

 

 

 

(in thousands)

 

As of September 30, 2013 -

 

 

 

 

 

 

 

Butane cross-commodity (1)

 

October 2013 — March 2015

 

858

 

$

(3,034

)

Crude oil cross-commodity (2)

 

October 2013 — March 2015

 

(633

)

(3,875

)

Crude oil fixed-price (3)

 

October 2013 — September 2014

 

(927

)

910

 

Crude oil index (4)

 

October 2013 — June 2014

 

434

 

555

 

Propane fixed-price (5)

 

October 2013 — March 2015

 

(904

)

(1,977

)

Butane fixed-price (6)

 

October 2013 — March 2014

 

(464

)

(1,208

)

Other

 

October 2013 — March 2014

 

26

 

(29

)

 

 

 

 

 

 

(8,658

)

Net cash collateral provided

 

 

 

 

 

2,745

 

Net fair value of commodity derivatives on consolidated balance sheet

 

 

 

 

 

$

(5,913

)

 

 

 

 

 

 

 

 

As of March 31, 2013 -

 

 

 

 

 

 

 

Butane cross-commodity (1)

 

April 2013 — March 2014

 

1,546

 

$

(2,557

)

Crude oil cross-commodity (2)

 

April 2013 — March 2014

 

(1,116

)

(7,651

)

Crude oil fixed-price (3)

 

April 2013 — March 2014

 

(144

)

1,033

 

Crude oil index (4)

 

April 2013 — June 2014

 

(91

)

153

 

Propane fixed-price (5)

 

April 2013 — March 2014

 

(282

)

3,197

 

Other

 

May 2013 — June 2013

 

8

 

79

 

 

 

 

 

 

 

(5,746

)

Net cash collateral held

 

 

 

 

 

(1,360

)

Net fair value of commodity derivatives on consolidated balance sheet

 

 

 

 

 

$

(7,106

)

 


(1)         Butane cross-commodity — Our natural gas liquids logistics segment purchases or sells certain commodities for which the pricing mechanism is based on a different commodity. The contracts listed in this table as “Butane cross-commodity”

 

32



Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

represent financial derivatives we have entered into as an economic hedge against the risk of changes in butane prices relative to the price of the other commodity.

 

(2)         Crude oil cross-commodity — Our natural gas liquids logistics segment purchases or sells certain commodities for which the pricing mechanism is based on a different commodity. The contracts listed in this table as “Crude oil cross-commodity” represent financial derivatives we have entered into as an economic hedge against the risk of changes in crude oil prices relative to the price of the other commodity.

 

(3)         Crude oil fixed-price — Our crude oil logistics segment routinely purchases crude oil inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Crude oil fixed-price” represent financial derivatives we have entered into as an economic hedge against the risk that crude oil prices will decline while we are holding the inventory.

 

(4)         Crude oil index — Our crude oil logistics segment routinely enters into crude oil purchase and sale contracts that are priced based on an index. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. The contracts listed in this table as “Crude oil index” represent financial derivatives entered into as economic hedges against the risk that changes in index price differentials would reduce the margins between the purchase and the sale transactions.

 

(5)         Propane fixed-price — Our natural gas liquids logistics segment routinely purchases propane inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Propane fixed-price” represent financial derivatives we have entered into as an economic hedge against the risk that propane prices will decline while we are holding the inventory.

 

(6)         Butane fixed-price — Our natural gas liquids logistics segment routinely purchases butane inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Butane fixed-price” represent financial derivatives we have entered into as an economic hedge against the risk that butane prices will decline while we are holding the inventory.

 

We recorded the following net gains (losses) from our commodity derivatives to cost of sales during the periods indicated:

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(in thousands)

 

Commodity contracts -

 

 

 

 

 

 

 

 

 

Unrealized gain (loss)

 

$

(167

)

$

9,476

 

$

(3,745

)

$

11,405

 

Realized gain (loss)

 

(10,505

)

(8,685

)

(14,136

)

(6,386

)

Total

 

$

(10,672

)

$

791

 

$

(17,881

)

$

5,019

 

 

Credit Risk

 

We maintain credit policies with regard to our counterparties on the 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 standardized agreements, which allow for netting of positive and negative exposure associated with a single counterparty.

 

Our counterparties consist primarily of financial institutions and energy companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

 

As is customary in the crude oil industry, we generally receive payment from customers for sales of crude oil on a monthly basis. As a result, receivables from individual customers in our crude oil marketing business are generally higher than the receivables from customers in our other segments.

 

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated statements of financial position and recognized in our net income.

 

Interest Rate Risk

 

The interest rate on our Revolving Credit Facility floats based on market indices. At September 30, 2013, we had $620.5 million of debt on our Revolving Credit Facility at a rate of 3.19% and $25.5 million of debt on our Revolving Credit Facility at a rate of 5.25%. A change of 0.125% in the interest rate would result in a change to annual interest expense of approximately $0.8 million on the revolving debt balance of $646.0 million.

 

Note 12 — Segments

 

Our reportable segments are based on the way in which our management structure is organized. Certain financial data related to our segments is shown below. Transactions between segments are recorded based on prices negotiated between the segments.

 

Our crude oil logistics segment sells crude oil and provides crude oil transportation services to wholesalers, refiners, and producers. Our water services segment provides services for the transportation, treatment, and disposal of wastewater generated from oil and natural gas production, and generates revenue from the sale of recycled wastewater and recovered hydrocarbons. Our natural gas liquids logistics segment supplies propane and other natural gas liquids, and provides natural gas liquids transportation, terminaling, and storage services to retailers, wholesalers, and refiners. Our natural gas liquids logistics segment consists of two divisions, which are organized based on the locations in which the divisions are headquartered. Our retail propane segment sells propane and distillates to end users consisting of residential, agricultural, commercial, and industrial customers, and to certain re-sellers. Our retail propane segment consists of two divisions, which are organized based on the location of the operations.

 

Items labeled “corporate and other” in the table below include the operations of a compressor leasing business that we acquired in our June 2012 merger with High Sierra, and also include certain corporate expenses that are incurred and are not allocated to the reportable segments. This data is included to reconcile the data for the reportable segments to data in our consolidated financial statements.

 

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

 

 

Crude oil logistics -

 

 

 

 

 

 

 

 

 

Crude oil sales

 

$

1,013,061

 

$

712,119

 

$

1,941,595

 

$

785,677

 

Other revenues

 

9,794

 

2,214

 

19,729

 

2,534

 

Water services -

 

 

 

 

 

 

 

 

 

Water treatment and disposal

 

28,823

 

12,724

 

47,511

 

14,236

 

Other revenues

 

5,367

 

3,086

 

7,192

 

3,515

 

Natural gas liquids logistics -

 

 

 

 

 

 

 

 

 

Propane sales

 

191,437

 

116,980

 

315,274

 

222,824

 

Other natural gas liquids sales

 

308,606

 

244,346

 

558,459

 

339,762

 

Other revenues

 

9,250

 

5,495

 

18,114

 

8,321

 

Retail propane -

 

 

 

 

 

 

 

 

 

Propane sales

 

40,651

 

37,939

 

87,342

 

77,791

 

Distillate sales

 

10,562

 

10,859

 

28,431

 

22,623

 

Other retail sales

 

8,198

 

8,205

 

15,898

 

15,797

 

Other

 

1,485

 

1,308

 

2,959

 

1,461

 

Elimination of intersegment sales

 

(33,297

)

(19,765

)

(62,610

)

(32,595

)

Total revenues

 

$

1,593,937

 

$

1,135,510

 

$

2,979,894

 

$

1,461,946

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization:

 

 

 

 

 

 

 

 

 

Crude oil logistics

 

$

3,330

 

$

1,680

 

$

8,014

 

$

1,940

 

Water services

 

11,438

 

2,768

 

18,794

 

3,050

 

Natural gas liquids logistics

 

2,672

 

3,553

 

5,376

 

5,450

 

Retail propane

 

6,871

 

5,187

 

14,111

 

11,928

 

Other

 

750

 

173

 

1,490

 

220

 

Total depreciation and amortization

 

$

25,061

 

$

13,361

 

$

47,785

 

$

22,588

 

 

 

 

 

 

 

 

 

 

 

Operating income (loss):

 

 

 

 

 

 

 

 

 

Crude oil logistics

 

$

5,884

 

$

10,129

 

$

12,493

 

$

5,819

 

Water services

 

2,913

 

4,377

 

5,956

 

4,547

 

Natural gas liquids logistics

 

14,605

 

10,217

 

12,490

 

11,402

 

Retail propane

 

(4,520

)

(469

)

(6,024

)

(6,640

)

Corporate and other

 

(8,937

)

(5,669

)

(22,312

)

(11,617

)

Total operating income

 

$

9,945

 

$

18,585

 

$

2,603

 

$

3,511

 

 

 

 

 

 

 

 

 

 

 

Other items not allocated by segment:

 

 

 

 

 

 

 

 

 

Interest expense

 

(11,060

)

(8,692

)

(21,682

)

(12,492

)

Loss on early extinguishment of debt

 

 

 

 

(5,769

)

Interest income

 

266

 

263

 

664

 

629

 

Other income (expense), net

 

153

 

3

 

(195

)

29

 

Income tax (expense) benefit

 

(236

)

(77

)

170

 

(536

)

Net income (loss)

 

$

(932

)

$

10,082

 

$

(18,440

)

$

(14,628

)

 

 

 

 

 

 

 

 

 

 

Additions to property, plant and equipment, including acquisitions (accrual basis):

 

 

 

 

 

 

 

 

 

Crude oil logistics

 

$

31,336

 

$

2,836

 

$

35,462

 

$

28,314

 

Water services

 

62,473

 

4,579

 

70,182

 

96,357

 

Natural gas liquids logistics

 

13,209

 

3,333

 

28,316

 

5,444

 

Retail propane

 

4,546

 

2,536

 

11,492

 

57,247

 

Other

 

217

 

1,213

 

846

 

13,357

 

Total

 

$

111,781

 

$

14,497

 

$

146,298

 

$

200,719

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

March 31,

 

 

 

 

 

 

 

2013

 

2013

 

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

Total assets:

 

 

 

 

 

 

 

 

 

Crude oil logistics

 

$

861,277

 

$

801,030

 

 

 

 

 

Water services

 

872,095

 

466,462

 

 

 

 

 

Natural gas liquids logistics

 

758,107

 

474,141

 

 

 

 

 

Retail propane

 

492,218

 

513,301

 

 

 

 

 

Corporate

 

42,796

 

36,413

 

 

 

 

 

Total

 

$

3,026,493

 

$

2,291,347

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-lived assets, net:

 

 

 

 

 

 

 

 

 

Crude oil logistics

 

$

432,886

 

$

356,750

 

 

 

 

 

Water services

 

844,231

 

453,986

 

 

 

 

 

Natural gas liquids logistics

 

258,972

 

238,192

 

 

 

 

 

Retail propane

 

439,577

 

441,762

 

 

 

 

 

Corporate

 

31,030

 

31,996

 

 

 

 

 

Total

 

$

2,006,696

 

$

1,522,686

 

 

 

 

 

 

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

Note 13 — Transactions with Affiliates

 

Since our business combination with SemStream on November 1, 2011, SemGroup Corporation (“SemGroup”) has held ownership interests in us and in our general partner, and has had the right to appoint two members to the Board of Directors of our general partner. Subsequent to November 1, 2011, our natural gas liquids logistics segment has sold natural gas liquids to and purchased natural gas liquids from affiliates of SemGroup. These transactions are included within revenues and cost of sales of our natural gas liquids logistics business in our consolidated statements of operations. We also made payments to SemGroup for certain administrative and operational services. These transactions are reported within operating and general and administrative expenses in our consolidated statements of operations.

 

Certain members of our management own interests in entities with which we have purchased products and services from and have sold products and services. The majority of these purchases represent crude oil purchases and are reported within cost of sales in our consolidated statements of operations, although approximately $3.7 million of these transactions during the six months ended September 30, 2013 represented capital expenditures and were recorded as increases to property, plant and equipment. The majority of these sales represent sales of crude oil and have been recorded within revenues in our consolidated statements of operations.

 

These transactions are summarized in the table below (in thousands):

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

 

Sales to SemGroup

 

$

3,780

 

$

11,598

 

$

3,780

 

$

24,280

 

Purchases from SemGroup

 

28,377

 

14,529

 

47,916

 

27,077

 

Sales to entities affiliated with management

 

58,769

 

1,137

 

109,872

 

1,326

 

Purchases from entities affiliated with management

 

48,522

 

13,895

 

56,346

 

15,651

 

 

Receivables from affiliates consist of the following (in thousands):

 

 

 

September 30,

 

March 31,

 

 

 

2013

 

2013

 

 

 

 

 

 

 

Receivables from entities affiliated with management

 

$

969

 

$

22,883

 

Receivables from SemGroup

 

2,102

 

 

 

 

$

3,071

 

$

22,883

 

 

Payables to related parties consist of the following (in thousands):

 

 

 

September 30,

 

March 31,

 

 

 

2013

 

2013

 

 

 

 

 

 

 

Payables to SemGroup

 

$

12,841

 

$

4,601

 

Payables to entities affiliated with management

 

5,588

 

2,299

 

 

 

$

18,429

 

$

6,900

 

 

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Table of Contents

 

NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2013 and March 31, 2013, and for the

Three Months and Six Months Ended September 30, 2013 and 2012

 

As described in Note 1, we completed a merger with High Sierra Energy, LP and High Sierra Energy GP, LLC in June 2012, which involved certain transactions with our general partner. We paid $91.8 million of cash, net of $5.0 million of cash acquired, and issued 18,018,468 common units to acquire High Sierra Energy, LP. We also paid $97.4 million of High Sierra Energy, LP’s long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our general partner.

 

We completed a business combination during the three months ended September 30, 2013 with an entity owned by an employee. We paid $11.0 million of cash for this acquisition.

 

Note 14 Subsequent Events

 

Senior Unsecured Notes

 

On October 16, 2013, we issued $450.0 million of senior unsecured notes (the “Unsecured Notes”) in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”) pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of approximately $438.4 million, after the initial purchasers’ discount of $10.1 million and estimated offering costs of $1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

 

The Unsecured Notes mature on October 15, 2021. We have the right to redeem the Unsecured Notes prior to the maturity date, although we would be required to pay a premium for early redemption. The notes bear interest at a fixed rate of 6.875%. Interest is payable on April 15 and October 15 of each year.

 

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

 

We also entered into a registration rights agreement whereby we have committed to exchange the Unsecured Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the Unsecured Notes on or before October 16, 2014. If we are unable to fulfill this obligation, we would be required to pay liquidated damages to the holders of the Unsecured Notes.

 

Gavilon Acquisition Agreement

 

On November 5, 2013, we entered into an agreement with Gavilon Energy Intermediate, LLC to acquire 100% of its equity interests in Gavilon, LLC (“Gavilon”), which is a midstream energy business with pipeline terminal and storage assets located in Oklahoma, Texas, and Louisiana. The purchase price is $890 million in cash, subject to adjustment based on a target level of working capital to be delivered by Gavilon at the closing of the transaction.  The acquisition agreement contains customary representations, warranties, indemnification obligations and covenants by the parties. The acquisition is expected to close in December 2013, subject to customary closing conditions including the expiration or termination of the waiting period under the Hart-Scott-Rodino Act.

 

Sale of Common Units

 

On November 5, 2013, we entered into an agreement to issue and sell 8,110,848 of our common units in a private placement at a price of $29.59 per common unit for approximately $240.0 million. The agreement for the sale of the common units includes customary representations and warranties, conditions, indemnification obligations and covenants by the parties. This sale of common units is subject to customary conditions to closing, and is expected to close in December 2013, concurrent with and contingent upon the closing of the Gavilon acquisition. The agreement will require us to register these units for resale under the Securities Act of 1933 within 90 days of the closing of the sale of the units.

 

Amendment to Credit Agreement

 

On November 5, 2013, we entered into an amendment to our Credit Agreement. This amendment increased the capacity on the Expansion Capital Facility from $725.0 million to $785.5 million and increased the capacity on the Working Capital Facility from $325.0 million to $885.5 million. This amendment also extended the maturity date of the agreement from June 19, 2017 to November 5, 2018.

 

Borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin or (ii) an adjusted LIBOR rate plus a margin. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. The amendment in November 2013 changed the margin on LIBOR rate borrowings from a range of 2.75% to 3.75% to a range of 1.50% to 2.50%. We paid fees of approximately $8.8 million to the lenders related to this amendment.

 

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Table of Contents

 

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

 

The following is a discussion of our financial condition and results of operations as of and for the three months and six months ended September 30, 2013. The discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the historical consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2013.

 

Overview

 

NGL Energy Partners LP (“we”, “us”, “our”, or the “Partnership”) is a Delaware limited partnership formed in September 2010. NGL Energy Holdings LLC serves as our general partner. At the time of formation, our operations included a wholesale natural gas liquids business and a retail propane business. We completed an initial public offering in May 2011. Subsequent to our initial public offering, we significantly expanded our operations through a number of business combinations, including the following:

 

·                  During October 2011, we completed a business combination with E. Osterman Propane, Inc., its affiliated companies and members of the Osterman family, whereby we acquired retail propane operations in the northeastern United States.

 

·                  During November 2011, we completed a business combination with SemStream, L.P. (“SemStream”), whereby we acquired SemStream’s wholesale natural gas liquids supply and marketing operations and its 12 natural gas liquids terminals.

 

·                  During January 2012, we completed a business combination with seven companies associated with Pacer Propane Holding, L.P., whereby we acquired retail propane operations, primarily in the western United States.

 

·                  During February 2012, we completed a business combination with North American Propane, Inc., whereby we acquired retail propane and distillate operations in the northeastern United States.

 

·                  During the year ended March 31, 2012, we completed three additional separate business combination transactions to acquire retail propane operations.

 

·                  On June 19, 2012, we completed a business combination with High Sierra Energy, LP and High Sierra Energy GP, LLC (collectively, “High Sierra”), whereby we acquired all of the ownership interests in High Sierra. High Sierra’s businesses include crude oil gathering, transportation and marketing; water treatment, disposal, and transportation; and natural gas liquids transportation and marketing.

 

·                  On November 1, 2012, we completed a business combination whereby we acquired Pecos Gathering & Marketing, L.L.C. and certain of its affiliated companies (collectively, “Pecos”). The business of Pecos consists primarily of crude oil purchasing and logistics operations in Texas and New Mexico.

 

·                  On December 31, 2012, we completed a business combination whereby we acquired all of the membership interests in Third Coast Towing, LLC (“Third Coast”). The business of Third Coast consists primarily of transporting crude oil via barge.

 

·                  During the year ended March 31, 2013, we completed six additional separate business combination transactions to acquire retail propane and distillate operations, primarily in the northeastern and southeastern United States.

 

·                  During the year ended March 31, 2013, we completed four additional separate acquisitions to expand the assets and operations of our crude oil logistics and water services businesses.

 

·                  During the six months ended September 30, 2013, we completed three acquisitions of retail propane and distillate businesses.

 

·                  On July 1, 2013, we completed a business combination whereby we acquired the assets of Crescent Terminals, LLC and the ownership interests in Cierra Marine, LP and its affiliated companies (collectively, “Crescent”), whereby we acquired four tow boats, seven crude oil barges, and one crude oil terminal in South Texas.

 

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Table of Contents

 

·                  On July 2, 2013, we completed a business combination with High Roller Wells Big Lake SWD No. 1, Ltd. (“Big Lake”), whereby we acquired a water disposal facility in West Texas. We also entered into a development agreement that provides us the option to purchase water disposal facilities that may be developed in the future.

 

·                  On August 2, 2013, we completed a business combination whereby we acquired seven entities affiliated with Oilfield Water Lines LP (collectively, “OWL”). The businesses of OWL include water disposal operations and a water transportation business in Texas.

 

·                  On September 1, 2013, we completed a business combination whereby we acquired a crude oil marketing business in Oklahoma and Texas.

 

·                  On September 3, 2013, we completed a business combination with Coastal Plains Disposal #1, LLC (“Coastal”), in which we acquired the ownership interests in a water disposal facility in Texas.

 

As of September 30, 2013, our businesses include:

 

·                  A crude oil logistics business, the assets of which include crude oil terminals, pipeline injection stations, a fleet of trucks, a fleet of leased rail cars, and a fleet of barges and tow boats. Our crude oil logistics business purchases crude oil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. The operations of our crude oil logistics segment began with our June 2012 merger with High Sierra.

 

·                  A water services business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks. Our water services business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons. The operations of our water services segment began with our June 2012 merger with High Sierra.

 

·                  Our natural gas liquids logistics business, which supplies natural gas liquids to retailers, wholesalers, and refiners throughout the United States and in Canada, and which provides natural gas liquids terminaling services through its 17 terminals throughout the United States and rail car transportation services through its fleet of owned and predominantly leased rail cars. Our natural gas liquids logistics segment purchases propane, butane, and other natural gas liquids from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets.

 

·                  Our retail propane business, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain re-sellers in more than 20 states.

 

Crude Oil Logistics

 

Our crude oil transportation and marketing business purchases crude oil from producers and transports it for resale at pipeline injection points, 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” contractual agreements whenever possible. In addition, we enter into forward contracts, financial swaps, and commodity spread trades as economic hedges of our physical forward sales and purchase contracts with our customers and suppliers.

 

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 price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by entering into financial derivatives. We utilize our transportation assets to move crude oil from the well head to the highest value market. The spread between crude oil prices in different markets can fluctuate widely, which may expand or limit our opportunity to generate margins by transporting crude oil to different markets. We also seek to maximize margins by blending crude oil of varying properties.

 

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Table of Contents

 

The range of high and low spot prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma for the period indicated and the prices as of period end are as follows:

 

 

 

Spot Price Per Barrel

 

 

 

Low

 

High

 

At Period End

 

For the Three Months Ended:

 

 

 

 

 

 

 

September 30, 2013

 

$

97.99

 

$

110.53

 

$

102.33

 

September 30, 2012

 

83.75

 

99.00

 

92.19

 

 

 

 

 

 

 

 

 

For the Six Months Ended:

 

 

 

 

 

 

 

September 30, 2013

 

$

86.68

 

$

110.53

 

$

102.33

 

September 30, 2012

 

77.69

 

106.16

 

92.19

 

 

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

 

Water Services

 

Our water services business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons. 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 services segment is the extent of exploration and production in the areas near our facilities, which is based upon producers’ expectations about the profitability of drilling new wells. The primary customers of our facility in Wyoming have committed to deliver a specified minimum volume of water to our facility under long-term contracts. The primary customers of our facilities in Colorado have committed to deliver to our facilities all wastewater produced at wells in a designated area. Most of the customers of our facilities in Texas are not under volume commitments, other than one customer that has committed to deliver 50,000 barrels per day to one of our facilities.

 

Natural Gas Liquids Logistics

 

Our natural gas liquids logistics segment purchases propane, butane, and other natural gas liquids from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets. Our natural gas liquids logistics segment owns 17 terminals and operates a fleet of owned and leased rail cars and leases underground storage capacity. We attempt to reduce our exposure to the impact of price fluctuations by using “back-to-back” contractual agreements and “pre-sale” agreements that essentially allow us to lock in a margin on a percentage of our winter volumes. We also attempt to reduce our exposure to the impact of price fluctuations by entering into swap agreements whereby we agree to pay a floating rate and receive a fixed rate on a specified notional amount of product. We enter into these agreements as economic hedges against the potential decline in the value of a portion of our inventory.

 

Our wholesale business is a “cost-plus” business that is affected both by 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 margins we realize in our wholesale business are substantially less as a percentage of revenues or on a per gallon basis than our retail propane business.

 

Weather conditions 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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Table of Contents

 

At Conway, Kansas and Mt. Belvieu, Texas, two of our main pricing hubs, the range of low and high spot propane prices per gallon for the periods indicated and the prices as of period end were as follows:

 

 

 

Conway, Kansas

 

Mt. Belvieu, Texas

 

 

 

Spot Price

 

Spot Price

 

Spot Price

 

Spot Price

 

 

 

Per Gallon

 

Per Gallon

 

Per Gallon

 

Per Gallon

 

 

 

Low

 

High

 

At Period End

 

Low

 

High

 

At Period End

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended:

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2013

 

$

0.81

 

$

1.16

 

$

1.01

 

$

0.86

 

$

1.19

 

$

1.05

 

September 30, 2012

 

0.51

 

0.88

 

0.79

 

0.79

 

0.99

 

0.92

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Six Months Ended:

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2013

 

$

0.77

 

$

1.16

 

$

1.01

 

$

0.81

 

$

1.19

 

$

1.05

 

September 30, 2012

 

0.50

 

0.96

 

0.79

 

0.71

 

1.22

 

0.92

 

 

The range of high and low spot butane prices per gallon at Mt. Belvieu, Texas are shown below for the periods indicated:

 

 

 

Spot Price Per Gallon

 

 

 

Low

 

High

 

At Period End

 

For the Three Months Ended:

 

 

 

 

 

 

 

September 30, 2013

 

$

1.19

 

$

1.44

 

$

1.38

 

September 30, 2012

 

1.23

 

1.59

 

1.44

 

 

 

 

 

 

 

 

 

For the Six Months Ended:

 

 

 

 

 

 

 

September 30, 2013

 

$

1.08

 

$

1.44

 

$

1.38

 

September 30, 2012

 

1.14

 

1.93

 

1.44

 

 

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 sells propane, distillates, and equipment and supplies to residential, agricultural, commercial, and industrial end-users. Our retail propane segment purchases the majority of its propane from our natural gas liquids logistics 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 have a significant impact on our sales volumes and prices, as a significant 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 realized product margin on a cents per gallon basis. Product margin is the differential between our sales prices and our total product costs, including transportation and storage. Historically, we have been successful in passing on price increases to our customers. We monitor propane and distillate prices daily and adjust our retail prices to maintain expected margins by passing on the wholesale costs to our customers. We believe that volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.

 

In periods of significant propane price increases we have experienced, and expect to continue to experience, conservation of propane used by our customers that could result in a decline in our sales volumes, revenues and gross margins. In periods of decreasing costs, we have typically experienced an increase in our product margin. The retail propane business is 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. Approximately 70% of our retail volume is sold during the peak heating season from October through March. 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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Recent Developments

 

Senior Unsecured Notes

 

On October 16, 2013, we issued $450.0 million of senior unsecured notes (the “Unsecured Notes”) in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”) pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of approximately $438.4 million, after the initial purchasers’ discount of $10.1 million and estimated offering costs of $1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

 

The Unsecured Notes mature on October 15, 2021. We have the right to redeem the Unsecured Notes prior to the maturity date, although we would be required to pay a premium for early redemption. The notes bear interest at a fixed rate of 6.875%. Interest is payable on April 15 and October 15 of each year.

 

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

 

We also entered into a registration rights agreement whereby we have committed to exchange the Unsecured Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the Unsecured Notes on or before October 16, 2014. If we are unable to fulfill this obligation, we would be required to pay liquidated damages to the holders of the Unsecured Notes.

 

Gavilon Acquisition Agreement

 

On November 5, 2013, we entered into an agreement with Gavilon Energy Intermediate, LLC to acquire 100% of its equity interests in Gavilon, LLC (“Gavilon”), which is a midstream energy business with pipeline terminal and storage assets located in Oklahoma, Texas, and Louisiana. The purchase price is $890 million in cash, subject to adjustment based on a target level of working capital to be delivered by Gavilon at the closing of the transaction.  The acquisition agreement contains customary representations, warranties, indemnification obligations and covenants by the parties. The acquisition is expected to close in December 2013, subject to customary closing conditions including the expiration or termination of the waiting period under the Hart-Scott-Rodino Act.

 

Sale of Common Units

 

On November 5, 2013, we entered into an agreement to issue and sell 8,110,848 of our common units in a private placement at a price of $29.59 per common unit for approximately $240.0 million. The agreement for the sale of the common units includes customary representations and warranties, conditions, indemnification obligations and covenants by the parties. This sale of common units is subject to customary conditions to closing, and is expected to close in December 2013, concurrent with and contingent upon the closing of the Gavilon acquisition. The agreement will require us to register these units for resale under the Securities Act of 1933 within 90 days of the closing of the sale of the units.

 

Amendment to Credit Agreement

 

On November 5, 2013, we entered into an amendment to our Credit Agreement. This amendment increased the capacity on the Expansion Capital Facility from $725.0 million to $785.5 million and increased the capacity on the Working Capital Facility from $325.0 million to $885.5 million. This amendment also extended the maturity date of the agreement from June 19, 2017 to November 5, 2018.

 

Borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin or (ii) an adjusted LIBOR rate plus a margin. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. The amendment in November 2013 changed the margin on LIBOR rate borrowings from a range of 2.75% to 3.75% to a range of 1.50% to 2.50%. We paid fees of approximately $8.8 million to the lenders related to this amendment.

 

Summary Discussion of Operating Results for the Three Months Ended September 30, 2013

 

During the three months ended September 30, 2013, we generated operating income of $9.9 million, compared to operating income of $18.6 million during the three months ended September 30, 2012.

 

Our crude oil logistics segment generated operating income of $5.9 million during the three months ended September 30, 2013, compared to operating income of $10.1 million during the three months ended September 30, 2012. Cost of sales was increased by $3.1 million during the three months ended September 30, 2013 due to unrealized losses on derivatives. Cost of sales was reduced by $6.7 million during the three months ended September 30, 2012 due to unrealized gains on derivatives. The impact of these unrealized gains and losses on derivatives impacted the comparability of operating income between the three months ended September 30, 2013 and the three months ended September 30, 2012 by $9.8 million. Acquisitions of business contributed to operating income during the three months ended September 30, 2013, although this benefit was partially offset by a narrowing of price differences between markets, which reduced our opportunities to generate increased margins by transporting product from lower-price to higher-price markets.

 

Our water services segment generated operating income of $2.9 million during the three months ended September 30, 2013, compared to operating income of $4.4 million during the three months ended September 30, 2012. The decrease in operating income was due primarily to an increase in depreciation and amortization expense, partially offset by operating income generated by water services businesses we acquired subsequent to our merger with High Sierra.

 

                Our natural gas liquids logistics segment generated operating income of $14.6 million during the three months ended September 30, 2013, compared to operating income of $10.2 million during the three months ended September 30, 2012. Market demand was greater during the three months ended September 30, 2013 than during the three months ended September 30, 2012, which resulted in higher sales volumes. Volumes also improved due to the expansion of our sales staff. In addition, during the year ended March 31, 2013, we refurbished two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals. Operating income during the three months ended September 30, 2013 also benefitted from $3.3 million of unrealized gains on derivatives, compared to $1.7 million of unrealized gains on derivatives during the three months ended September 30, 2012.

 

Our retail propane segment generated an operating loss of $4.5 million during the three months ended September 30, 2013, compared to an operating loss of $0.5 million during the three months ended September 30, 2012. Due to the seasonal nature of demand for propane and distillates, sales volumes of our retail propane business are lower during the first and second quarters of the fiscal year than during the third and fourth quarters of the fiscal year. Sales volumes and product margins during the three months ended September 30, 2013 were similar to volumes and product margins during the three months ended September 30, 2012, except that cost of sales during the three months ended September 30, 2012 were reduced by $1.8 million of unrealized gains on derivatives. These derivatives were entered into as hedges against potential increases in the cost of distillates. During the three months ended September 30, 2013, we have primarily used physical contracts accounted for as normal purchases, rather than financial derivatives, to hedge against potential increases in the cost of distillates. Depreciation and amortization expense was higher during the three months ended September 30, 2013 than during the three months ended September 30, 2012.

 

We incurred interest expense of $11.1 million during the three months ended September 30, 2013. This was higher than the interest expense of $8.7 million during the three months ended September 30, 2012, due primarily to borrowings to finance acquisitions.

 

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Consolidated Results of Operations

 

The following table summarizes our historical unaudited consolidated statements of operations for the three months and six months ended September 30, 2013 and 2012.

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(in thousands)

 

Revenues

 

$

1,593,937

 

$

1,135,510

 

$

2,979,894

 

$

1,461,946

 

Cost of sales

 

1,488,850

 

1,053,690

 

2,791,926

 

1,352,675

 

Operating and general and administrative expenses

 

70,081

 

49,874

 

137,580

 

83,172

 

Depreciation and amortization

 

25,061

 

13,361

 

47,785

 

22,588

 

Operating income

 

9,945

 

18,585

 

2,603

 

3,511

 

Interest expense

 

(11,060

)

(8,692

)

(21,682

)

(12,492

)

Loss on early extinguishment of debt

 

 

 

 

(5,769

)

Interest and other income, net

 

419

 

266

 

469

 

658

 

Income (loss) before income taxes

 

(696

)

10,159

 

(18,610

)

(14,092

)

Income tax (provision) benefit

 

(236

)

(77

)

170

 

(536

)

Net income (loss)

 

(932

)

10,082

 

(18,440

)

(14,628

)

Net income allocated to general partner

 

(2,451

)

(694

)

(4,139

)

(789

)

Net (income) loss attributable to noncontrolling interests

 

(9

)

(9

)

(134

)

51

 

Net income (loss) attributable to parent equity allocated to limited partners

 

$

(3,392

)

$

9,379

 

$

(22,713

)

$

(15,366

)

 

See the detailed discussion of revenues, cost of sales, operating expenses, general and administrative expenses, depreciation and amortization and operating income by operating segment below. The business combinations described above had a significant impact on the comparability of our results of operations for the three months ended September 30, 2013 and 2012.

 

Interest Expense

 

The largest component of interest expense during the six months ended September 30, 2013 and 2012 was interest on revolving credit facilities and on senior notes that we issued in June 2012. See Note 7 to our consolidated financial statements included elsewhere in this Quarterly Report for additional information on our long-term debt. The change in interest expense during the periods presented is due primarily to fluctuations in the average outstanding debt balance, as summarized below:

 

 

 

Average Debt

 

 

 

Average Debt

 

 

 

 

 

Balance

 

 

 

Balance

 

 

 

 

 

Outstanding -

 

Average

 

Outstanding -

 

 

 

 

 

Revolving Facilities

 

Interest Rate -

 

Senior Notes

 

Interest Rate -

 

 

 

(in thousands)

 

Revolving Facilities

 

(in thousands)

 

Senior Notes

 

Three Months Ended September 30,

 

 

 

 

 

 

 

 

 

2013

 

$

572,353

 

3.63

%

$

250,000

 

6.65

%

2012

 

366,283

 

3.46

%

250,000

 

6.65

%

Six Months Ended September 30,

 

 

 

 

 

 

 

 

 

2013

 

$

521,202

 

3.65

%

$

250,000

 

6.65

%

2012

 

320,272

 

3.61

%

142,077

 

6.65

%

 

Interest expense also includes amortization of debt issuance costs, which represented $1.1 million of expense during the three months ended September 30, 2013 and $0.8 million of expense during the three months ended September 30, 2012. Debt issuance costs represented $2.5 million of expense during the six months ended September 30, 2013 and $1.3 million of expense during the six

 

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months ended September 30, 2012. Interest expense also includes letter of credit fees, interest on equipment financing notes, and accretion of interest on non-interest bearing debt obligations assumed in business combinations.

 

On June 19, 2012, we retired our previous revolving credit facility. Upon retirement of this facility, we wrote off the portion of the debt issuance cost asset that had not yet been amortized. This expense is reported as “Loss on early extinguishment of debt” in our consolidated statement of operations for the six months ended September 30, 2012.

 

The increased level of debt outstanding during the three months and six months ended September 30, 2013 is due primarily to borrowings to finance acquisitions.

 

Income Tax Provision

 

We believe that we qualify as a partnership for income tax purposes. As such, we generally do not pay U.S. federal income tax. Rather, each owner reports his or her share of our income or loss on his or her individual tax return.

 

We have two taxable corporate subsidiaries in the United States and three taxable corporate subsidiaries in Canada. The income tax provision reported in our consolidated statements of operations relates primarily to these subsidiaries.

 

See Note 8 to our consolidated financial statements included elsewhere in this annual report for additional description of income tax provisions.

 

Noncontrolling Interests

 

As of September 30, 2013, we have three consolidated subsidiaries in which outside parties own interests. Our ownership interests in these subsidiaries range from 60% to 80%. The noncontrolling interest shown in our consolidated statements of operations represents the other owners’ share of the net income of these entities.

 

Non-GAAP Financial Measures

 

The following table reconciles net loss attributable to parent equity to our EBITDA and Adjusted EBITDA, each of which are non-GAAP financial measures, for the periods indicated:

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(in thousands)

 

EBITDA:

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to parent equity

 

$

(941

)

$

10,073

 

$

(18,574

)

$

(14,577

)

Provision (benefit) for income taxes

 

236

 

77

 

(170

)

536

 

Interest expense

 

11,060

 

8,692

 

21,682

 

12,492

 

Loss on early extinguishment of debt

 

 

 

 

5,769

 

Depreciation and amortization expense

 

25,753

 

14,699

 

48,948

 

24,113

 

EBITDA

 

$

36,108

 

$

33,541

 

$

51,886

 

$

28,333

 

Unrealized (gain) loss on derivative contracts

 

167

 

(9,476

)

3,745

 

(11,405

)

Loss (gain) on disposal of assets

 

1,790

 

(30

)

2,163

 

(23

)

Share-based compensation expense

 

3,217

 

2,302

 

10,292

 

2,957

 

Adjusted EBITDA

 

$

41,282

 

$

26,337

 

$

68,086

 

$

19,862

 

 

We define EBITDA as net income (loss) attributable to parent equity, plus income taxes, interest expense and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding the unrealized gain or loss on derivative contracts, the gain or loss on the disposal of assets, and share-based compensation expense. EBITDA and Adjusted EBITDA should not be considered an alternative 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 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 for evaluating our financial performance without regard to our financing methods, capital structure

 

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Table of Contents

 

and historical cost basis. Further, EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other entities.

 

Segment Operating Results for the Three Months Ended September 30, 2013 and 2012

 

Items Impacting the Comparability of Our Financial Results

 

Our results of operations for the three months ended September 30, 2013 may not be comparable to our results of operations for the three months ended September 30, 2012, due to the business combinations described above. The results of operations of our natural gas liquids businesses are impacted by seasonality, primarily due to the increase in volumes sold by our retail and wholesale natural gas liquids businesses during the peak heating season of October through March. In addition, product price fluctuations can have a significant impact on our sales volumes. For these and other reasons, our results of operations for the three months ended September 30, 2013 are not necessarily indicative of the results to be expected for the full fiscal year.

 

Volumes Sold or Delivered

 

The following table summarizes the volume of product sold and wastewater delivered for the three months ended September 30, 2013 and 2012. Volumes shown in the table below for our natural gas liquids logistics segment include sales to our retail segment.

 

 

 

Three Months Ended

 

 

 

 

 

September 30,

 

 

 

Segment

 

2013

 

2012

 

Change

 

 

 

(in thousands)

 

Crude oil logistics

 

 

 

 

 

 

 

Crude oil sold (barrels)

 

9,280

 

7,479

 

1,801

 

 

 

 

 

 

 

 

 

Water services

 

 

 

 

 

 

 

Water delivered (barrels)

 

16,459

 

6,036

 

10,423

 

 

 

 

 

 

 

 

 

Natural gas liquids logistics

 

 

 

 

 

 

 

Propane sold (gallons)

 

183,415

 

137,840

 

45,575

 

Other natural gas liquids sold (gallons)

 

294,809

 

186,795

 

108,014

 

 

 

 

 

 

 

 

 

Retail propane

 

 

 

 

 

 

 

Propane sold (gallons)

 

20,599

 

20,057

 

542

 

Distillates sold (gallons)

 

3,072

 

3,024

 

48

 

 

Volumes sold by our crude oil logistics and water services segments were higher during the three months ended September 30, 2013 than during the three months ended September 30, 2012, due primarily to the expansion of our business through acquisitions.

 

Volumes sold by our natural gas liquids logistics segment were higher during the three months ended September 30, 2013 than during the three months ended September 30, 2012, due to several factors. Market demand for propane was higher, due in part to colder weather conditions. Market demand for butane to be used in gasoline blending operations was also higher. Volumes also increased due to the expansion of our sales staff. In addition, during the year ended March 31, 2013, we refurbished two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

 

Volumes sold by our retail propane segment during the three months ended September 30, 2013 were similar to volumes sold during the three months ended September 30, 2012.

 

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Table of Contents

 

Operating Income (Loss) by Segment

 

Our operating income (loss) by segment was as follows:

 

 

 

Three Months Ended

 

 

 

 

 

September 30,

 

 

 

Segment

 

2013

 

2012

 

Change

 

 

 

(in thousands)

 

Crude oil logistics

 

$

5,884

 

$

10,129

 

$

(4,245

)

Water services

 

2,913

 

4,377

 

(1,464

)

Natural gas liquids logistics

 

14,605

 

10,217

 

4,388

 

Retail propane

 

(4,520

)

(469

)

(4,051

)

Corporate and other

 

(8,937

)

(5,669

)

(3,268

)

Operating income

 

$

9,945

 

$

18,585

 

$

(8,640

)

 

The operating loss within “corporate and other” for the three months ended September 30, 2013 includes approximately $3.2 million of expense related to equity-based compensation, approximately $0.8 million of expenses related to acquisitions, and approximately $4.7 million of other corporate expenses.

 

The operating loss within “corporate and other” for the three months ended September 30, 2012 includes approximately $2.3 million of expense related to equity-based compensation, approximately $0.6 million of expenses related to acquisitions, and approximately $3.2 million of other corporate expenses.

 

The increase in equity-based compensation expense is due in part to the fact that more awards were outstanding during the three months ended September 30, 2013 than during the three months ended September 30, 2012. The increase in expense is also due to the fact that the expense is recorded over the vesting period of the awards, and is adjusted based on the value of the common units at the end of the reporting period. The value of the common units was higher at September 30, 2013 than at September 30, 2012.

 

The decrease in acquisition-related expenses is due primarily to the fact that $3.5 million of expense was recorded during the three months ended September 30, 2012 related to the merger with High Sierra.

 

The increase in other corporate expenses is due primarily to increases in compensation expense, due to the addition of new corporate employees to provide general and administrative services in support of the growth of our business.

 

The operations of our compressor leasing business, which was acquired in our merger with High Sierra, are also included within “corporate and other.”

 

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Table of Contents

 

Crude Oil Logistics

 

The following table summarizes the operating results of our crude oil logistics segment for the three months ended September 30, 2013 and 2012 (amounts in thousands).

 

 

 

Three Months Ended

 

 

 

 

 

September 30,

 

 

 

 

 

2013

 

2012

 

Change

 

Revenues:

 

 

 

 

 

 

 

Crude oil sales

 

$

1,013,061

 

$

712,119

 

$

300,942

 

Other revenues

 

9,794

 

2,214

 

7,580

 

Total revenues(1)

 

1,022,855

 

714,333

 

308,522

 

Expenses:

 

 

 

 

 

 

 

Cost of sales

 

1,000,982

 

696,999

 

303,983

 

Operating expenses

 

11,760

 

4,816

 

6,944

 

General and administrative expenses

 

899

 

709

 

190

 

Depreciation and amortization expense

 

3,330

 

1,680

 

1,650

 

Total expenses

 

1,016,971

 

704,204

 

312,767

 

 

 

 

 

 

 

 

 

Segment operating income

 

$

5,884

 

$

10,129

 

$

(4,245

)

 


(1)         Revenues include $8.8 million of intersegment sales during the three months ended September 30, 2013 and $3.3 million of intersegment sales during the three months ended September 30, 2012 that are eliminated in our consolidated statement of operations.

 

Revenues. We generated revenue of $1.0 billion from crude oil sales during the three months ended September 30, 2013, selling 9.3 million barrels at an average price of $109.17 per barrel. During the three months ended September 30, 2012, we generated revenue of $712.2 million from crude oil sales, selling 7.5 million barrels at an average price of $95.22 per barrel. The increase in volume during the three months ended September 30, 2013 compared to the three months ended September 30, 2012 was due primarily to acquisitions of crude oil logistics businesses, including Pecos and Third Coast, among others.

 

Other revenues of our crude oil logistics segment were $9.8 million during the three months ended September 30, 2013, compared to other revenues of $2.2 million during the three months ended September 30, 2012, due primarily to acquisitions of crude oil logistics businesses, including Pecos and Third Coast.

 

Cost of Sales. Our cost of crude oil sold was $1.0 billion during the three months ended September 30, 2013. We sold 9.3 million barrels at an average cost of $107.86 per barrel. Our cost of sales during the three months ended September 30, 2013 was increased by $3.1 million of unrealized losses and $1.7 million of realized losses on derivatives. During the three months ended September 30, 2012, our cost of crude oil sold was $697.0 million. We sold 7.5 million barrels at an average cost of $93.19 per barrel. Our cost of sales during the three months ended September 30, 2012 was increased by $9.9 million of realized losses on derivatives, which was partially offset by $6.7 million of unrealized gains on derivatives.

 

Operating Expenses. Our crude oil logistics segment generated $11.8 million of operating expenses during the three months ended September 30, 2013, compared to $4.8 million of operating expenses during the three months ended September 30, 2012. This increase was due primarily to the expansion of operations resulting from acquisitions, including Pecos and Third Coast.

 

General and Administrative Expenses. Our crude oil logistics segment generated $0.9 million of general and administrative expenses during the three months ended September 30, 2013, compared to $0.7 million of general and administrative expenses during the three months ended September 30, 2012.

 

Depreciation and Amortization Expense. Our crude oil logistics segment generated depreciation and amortization expense of $3.3 million during the three months ended September 30, 2013, compared to depreciation and amortization expense of $1.7 million during the three months ended September 30, 2012. This increase was due primarily to the expansion of operations resulting from acquisitions.

 

Operating Income. Our crude oil logistics segment generated operating income of $5.9 million during the three months ended September 30, 2013, compared to operating income of $10.1 million during the three months ended September 30, 2012. Cost of sales was increased by $3.1 million during the three months ended September 30, 2013 due to unrealized losses on derivatives. Cost of sales was decreased by $6.7 million during the three months ended September 30, 2012 due to unrealized gains on derivatives. The impact of these unrealized gains and losses on derivatives impacted the comparability of operating income between the three months ended September 30, 2013 and the three months ended September 30, 2012 by $9.8 million. Acquisitions of businesses contributed to operating income during the three months ended September 30, 2013, although this benefit was partially offset by a narrowing of price differences between markets, which reduced our opportunities to generate increased margins by transporting product from lower-price to higher-price markets.

 

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Water Services

 

The following table summarizes the operating results of our water services segment for the three months ended September 30, 2013 and 2012 (amounts in thousands).

 

 

 

Three Months Ended

 

 

 

 

 

September 30,

 

Change

 

 

 

2013

 

2012

 

Acquisitions (1)

 

Other

 

Revenues:

 

 

 

 

 

 

 

 

 

Water treatment and disposal

 

$

28,823

 

$

12,724

 

$

16,498

 

$

(399

)

Water transportation

 

5,367

 

3,086

 

3,873

 

(1,592

)

Total revenues

 

34,190

 

15,810

 

20,371

 

(1,991

)

Expenses:

 

 

 

 

 

 

 

 

 

Cost of sales

 

3,782

 

2,054

 

2,419

 

(691

)

Operating expenses

 

15,003

 

6,154

 

10,503

 

(1,654

)

General and administrative expenses

 

1,054

 

457

 

211

 

386

 

Depreciation and amortization expense

 

11,438

 

2,768

 

5,133

 

3,537

 

Total expenses

 

31,277

 

11,433

 

18,266

 

1,578

 

 

 

 

 

 

 

 

 

 

 

Segment operating income

 

$

2,913

 

$

4,377

 

$

2,105

 

$

(3,569

)

 


(1)   Represents the change in revenues and expenses attributable to acquisitions subsequent to the merger with High Sierra.

 

Revenues. Our water services segment generated $28.8 million of treatment and disposal revenue during the three months ended September 30, 2013, taking delivery of 16.5 million barrels of wastewater at an average revenue of $1.75 per barrel. During the three months ended September 30, 2012, our water services segment generated $12.7 million of treatment and disposal revenue, taking delivery of 6.0 million barrels of wastewater at an average revenue of $2.11 per barrel. The increase in revenues was due primarily to acquisitions, including OWL, Big Lake, and Coastal. The decrease in revenue per barrel is due primarily to the fact that the expansion of our water services business subsequent to our merger with High Sierra has been primarily in Texas, where the market rates for water disposal services are typically lower than in Wyoming and Colorado.

 

Our water services segment generated transportation revenues of $5.4 million during the three months ended September 30, 2013, compared to transportation revenues of $3.1 million during the three months ended September 30, 2012. This was due to acquisition of OWL, which generated transportation revenues of $3.9 million. This increase was partially offset by a decrease in water transportation revenues generated by the water services business acquired in the merger with High Sierra, which resulted primarily from a slowdown in production activities by a customer.

 

Cost of Sales. The cost of sales for our water services segment was $3.8 million for the three months ended September 30, 2013. Cost of sales was increased by $0.9 million of realized losses and $0.3 million of unrealized losses on derivatives. Because a portion of our processing revenue is generated from the sale of recovered hydrocarbons, we enter into derivatives to protect against the risk of a decline in the market price of a portion of the hydrocarbons we expect to recover. During the three months ended September 30, 2012, the cost of sales for our water services segment was $2.1 million, which included $0.8 million of unrealized losses and $0.4 million of realized losses on derivatives.

 

Operating Expenses. Our water services segment generated $15.0 million of operating expenses during the three months ended September 30, 2013, compared to $6.2 million of operating expenses during the three months ended September 30, 2012. This increase was due to acquisitions of businesses. We incurred losses on disposal of property, plant and equipment of $2.0 million during the three months ended September 30, 2013 as a result of property damage resulting from lightning strikes at two of our facilities.

 

General and Administrative Expenses. Our water services segment generated $1.1 million of general and administrative expenses during the three months ended September 30, 2013, compared to $0.5 million of general and administrative expenses during the three months ended September 30, 2012. This increase was due in part to acquisitions of businesses.

 

Depreciation and Amortization Expense. Our water services segment generated depreciation and amortization expense of $11.4 million during the three months ended September 30, 2013, compared to depreciation and amortization expense of $2.8 million during the three months ended September 30, 2012. This increase was due primarily to the acquisitions of businesses.

 

Operating Income. Our water services segment generated $2.9 million of operating income during the three months ended September 30, 2013, compared to operating income of $4.4 million during the three months ended September 30, 2012. The decrease in operating income was due primarily to an increase in depreciation and amortization expense, partially offset by operating income generated by acquired businesses.

 

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Natural Gas Liquids Logistics

 

The following table compares the operating results of our natural gas liquids logistics segment for the three months ended September 30, 2013 and 2012:

 

 

 

Three Months Ended

 

 

 

 

 

September 30,

 

 

 

 

 

2013

 

2012

 

Change

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Propane sales

 

$

191,437

 

$

116,980

 

$

74,457

 

Other natural gas liquids sales

 

308,606

 

244,346

 

64,260

 

Other revenues

 

9,250

 

5,495

 

3,755

 

Total revenues (1)

 

509,293

 

366,821

 

142,472

 

 

 

 

 

 

 

 

 

Expenses:

 

 

 

 

 

 

 

Cost of sales - propane

 

184,565

 

111,870

 

72,695

 

Cost of sales - other NGLs

 

292,142

 

230,098

 

62,044

 

Cost of sales - storage

 

7,106

 

2,768

 

4,338

 

Operating expenses

 

6,800

 

7,128

 

(328

)

General and administrative expenses

 

1,403

 

1,187

 

216

 

Depreciation and amortization expense

 

2,672

 

3,553

 

(881

)

Total expenses

 

494,688

 

356,604

 

138,084

 

 

 

 

 

 

 

 

 

Segment operating income

 

$

14,605

 

$

10,217

 

$

4,388

 

 


(1)         The revenues in this table include $24.4 million of sales to our retail propane and crude oil logistics segments during the three months ended September 30, 2013 and $16.5 million of sales to our retail propane segment during the three months ended September 30, 2012. These intercompany sales, along with a corresponding amount of cost of sales, are eliminated in our consolidated statements of operations.

 

Revenues. Revenues from wholesale propane sales increased approximately $74.5 million during the three months ended September 30, 2013, as compared to $117.0 million during the three months ended September 30, 2012. This resulted from an increase in the volume sold of 45.6 million gallons, as compared to 137.8 million gallons sold during the three months ended September 30, 2012, and an increase in the sales price per gallon of $0.19 per gallon, as compared to $0.85 per gallon during the three months ended September 30, 2012. The increase in volumes during the three months ended September 30, 2013 as compared to the three months ended September 30, 2012 is due to several factors. Market demand was higher, due in part to colder weather conditions. Volumes also increased due to the expansion of our sales staff. In addition, during the year ended March 31, 2013, we refurbished two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

 

Revenues from wholesale sales of other natural gas liquids increased approximately $64.3 million during the three months ended September 30, 2013, as compared to $244.3 million during the three months ended September 30, 2012. This resulted from an increase in volume sold of 108.0 million gallons, as compared to 186.8 million gallons sold during the three months ended September 30, 2012, partially offset by a decrease in the sales price per gallon of $0.26 per gallon, as compared to $1.31 per gallon during the three months ended September 30, 2012. The increase in volumes during the three months ended September 30, 2013 as compared to the three months ended September 30, 2012 is due to several factors. Market demand for butane to be used in gasoline blending operations was higher. Volumes also increased due to the expansion of our sales staff and to an increased focus on the opportunity to more fully utilize our terminals to market butane.

 

Cost of Sales. Costs of wholesale propane sales increased approximately $72.7 million during the three months ended September 30, 2013, as compared to $111.9 million during the three months ended September 30, 2012. This resulted from an increase in the volume sold of 45.6 million gallons, as compared to 137.8 million gallons sold during the three months ended September 30, 2012 and an increase in the cost per gallon of $0.20, as compared to $0.81 per gallon during the three months ended

 

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September 30, 2012. Cost of propane sales during the three months ended September 30, 2013 were increased by $4.0 million of net losses on derivatives, which included $3.6 million of unrealized losses and $0.4 million of realized losses. Cost of propane sales during the three months ended September 30, 2012 were increased by $1.9 million of unrealized losses on derivatives, which was partially offset by $1.1 million of realized gains on derivatives.

 

Cost of wholesale sales of other natural gas liquids increased approximately $62.0 million during the three months ended September 30, 2013, as compared to $230.1 million during the three months ended September 30, 2012. This resulted from an increase in volume sold of approximately 108.0 million gallons as compared to 186.8 million gallons sold during the three months ended September 30, 2012, partially offset by a decrease in the average cost of $0.24 per gallon, as compared to $1.23 per gallon in the prior year. Cost of sales of other natural gas liquids during the three months ended September 30, 2013 were increased by $7.4 million of realized losses on derivatives, which was partially offset by $6.9 million of realized gains on derivatives. Cost of sales of other natural gas liquids during the three months ended September 30, 2012 were reduced by $3.7 million of unrealized gains and $0.5 million of realized gains on derivatives.

 

Operating Expenses. Operating expenses of our natural gas liquids logistics segment decreased approximately $0.3 million during the three months ended September 30, 2013 as compared to operating expenses of $7.1 million during the three months ended September 30, 2012.

 

General and Administrative Expenses. General and administrative expenses of our natural gas liquids logistics segment increased approximately $0.2 million during the three months ended September 30, 2013 as compared to general and administrative expenses of $1.2 million during the three months ended September 30, 2012.

 

Depreciation and Amortization Expense. Depreciation and amortization expense of our natural gas liquids logistics segment decreased approximately $0.9 million during the three months ended September 30, 2013, as compared to depreciation and amortization expense of approximately $3.6 million during the three months ended September 30, 2012.

 

Operating Income. Our natural gas liquids logistics segment generated operating income of $14.6 million during the three months ended September 30, 2013 as compared to operating income of $10.2 million during the three months ended September 30, 2012.

 

Retail Propane

 

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

 

 

 

Three Months Ended

 

 

 

 

 

September 30,

 

 

 

 

 

2013

 

2012

 

Change

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Propane sales

 

$

40,651

 

$

37,939

 

$

2,712

 

Distillate sales

 

10,562

 

10,859

 

(297

)

Other revenues

 

8,198

 

8,205

 

(7

)

Total revenues

 

59,411

 

57,003

 

2,408

 

Expenses:

 

 

 

 

 

 

 

Cost of sales - propane

 

21,848

 

19,296

 

2,552

 

Cost of sales - distillates

 

9,265

 

7,276

 

1,989

 

Cost of sales - other

 

2,457

 

3,094

 

(637

)

Operating expenses

 

20,997

 

20,626

 

371

 

General and administrative expenses

 

2,493

 

1,993

 

500

 

Depreciation and amortization expense

 

6,871

 

5,187

 

1,684

 

Total expenses

 

63,931

 

57,472

 

6,459

 

 

 

 

 

 

 

 

 

Segment operating loss

 

$

(4,520

)

$

(469

)

$

(4,051

)

 

Revenues. Propane sales for the three months ended September 30, 2013 increased approximately $2.7 million as compared to propane sales of $37.9 million during the three months ended September 30, 2012. The increase in revenue was due primarily to an increase in the average price per gallon sold of $0.08, as compared to an average price per gallon sold of $1.89 during the three

 

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months ended September 30, 2012. The increase in revenues was also due in part to an increase of 0.5 million gallons sold, as compared to 20.1 million gallons sold during the three months ended September 30, 2012.

 

Distillate sales for the three months ended September 30, 2013 decreased approximately $0.3 million as compared to distillate sales of $10.9 million during the three months ended September 30, 2012, due primarily to a decrease in the average selling price of $0.15 per gallon, as compared to an average selling price of $3.59 per gallon during the three months ended September 30, 2012.

 

Cost of Sales. Propane cost of sales for the three months ended September 30, 2013 increased approximately $2.6 million as compared to propane cost of sales of $19.3 million during the three months ended September 30, 2012. This increase was due primarily to an increase in the average cost per gallon sold of $0.10, as compared to an average cost per gallon sold of $0.96 during the three months ended September 30, 2012. The increase in cost of sales was also due in part to an increase of 0.5 million gallons sold, as compared to 20.1 million gallons sold during the three months ended September 30, 2012.

 

Distillate cost of sales for the three months ended September 30, 2013 increased approximately $2.0 million as compared to distillate cost of sales of $7.3 million during the three months ended September 30, 2012. This increase was due primarily to an increase in the cost per gallon sold of $0.61, as compared to a cost per gallon sold of $2.41 during the three months ended September 30, 2012. Cost of distillate sales during the three months ended September 30, 2012 were reduced by $1.8 million of unrealized gains on derivatives.

 

Operating Expenses. Operating expenses of our retail propane segment increased approximately $0.4 million during the three months ended September 30, 2013 as compared to operating expenses of $20.6 million during the three months ended September 30, 2012.

 

General and Administrative Expenses. General and administrative expenses of our retail propane segment increased approximately $0.5 million during the three months ended September 30, 2013 as compared to general and administrative expenses of $2.0 million during the three months ended September 30, 2012.

 

Depreciation and Amortization Expense. Depreciation and amortization expense of our retail propane segment increased approximately $1.7 million during the three months ended September 30, 2013 as compared to depreciation and amortization expense of $5.2 million during the three months ended September 30, 2012.

 

Operating Loss. Our retail propane segment had an operating loss of approximately $4.5 million during the three months ended September 30, 2013 compared to an operating loss of $0.5 million during the three months ended September 30, 2012. The increased operating loss was due in part to lower product margins on distillate sales; during the three months ended September 30, 2012, distillate cost of sales was reduced by $1.8 million due to unrealized gains on derivatives. Increased depreciation and amortization expense also contributed to the increased operating loss.

 

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Segment Operating Results for the Six Months Ended September 30, 2013 and 2012

 

Items Impacting the Comparability of Our Financial Results

 

Our results of operations for the six months ended September 30, 2013 may not be comparable to our results of operations for the six months ended September 30, 2012, due to the business combinations described above. The results of operations of our natural gas liquids businesses are impacted by seasonality, primarily due to the increase in volumes sold by our retail and wholesale natural gas liquids businesses during the peak heating season of October through March. In addition, product price fluctuations can have a significant impact on our sales volumes. For these and other reasons, our results of operations for the six months ended September 30, 2013 are not necessarily indicative of the results to be expected for the full fiscal year.

 

Volumes Sold or Delivered

 

The following table summarizes the volume of product sold and wastewater delivered for the six months ended September 30, 2013 and 2012. Volumes shown in the table below for our natural gas liquids logistics segment include sales to our retail segment.

 

 

 

Six Months Ended

 

 

 

 

 

September 30,

 

 

 

Segment

 

2013

 

2012

 

Change

 

 

 

(in thousands)

 

Crude oil logistics

 

 

 

 

 

 

 

Crude oil sold (barrels)

 

18,535

 

8,461

 

10,074

 

 

 

 

 

 

 

 

 

Water services

 

 

 

 

 

 

 

Water delivered (barrels)

 

26,498

 

6,775

 

19,723

 

 

 

 

 

 

 

 

 

Natural gas liquids logistics

 

 

 

 

 

 

 

Propane sold (gallons)

 

310,834

 

256,755

 

54,079

 

Other natural gas liquids sold (gallons)

 

544,061

 

251,750

 

292,311

 

 

 

 

 

 

 

 

 

Retail propane

 

 

 

 

 

 

 

Propane sold (gallons)

 

43,992

 

39,327

 

4,665

 

Distillates sold (gallons)

 

8,176

 

6,273

 

1,903

 

 

Volumes sold by our crude oil logistics and water services segments were higher during the six months ended September 30, 2013 than during the six months ended September 30, 2012, due primarily to the expansion of our business through acquisitions and to the fact that we did not acquire these segments until our June 19, 2012 merger with High Sierra.

 

Volumes sold by our natural gas liquids logistics segment were higher during the six months ended September 30, 2013 than during the six months ended September 30, 2012, due to several factors. Market demand for propane was higher, due in part to colder weather conditions. Market demand for butane to be used in gasoline blending operations was also higher. Volumes also increased due to the expansion of our sales staff. In addition, during the year ended March 31, 2013, we refurbished two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

 

Volumes sold by our retail propane were higher during the six months ended September 30, 2013 than during the six months ended September 30, 2012, due to improved market demand and to the acquisition of Downeast Energy Corp (“Downeast”) on May 1, 2012.

 

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Table of Contents

 

Operating Income (Loss) by Segment

 

Our operating income (loss) by segment was as follows:

 

 

 

Six Months Ended

 

 

 

 

 

September 30,

 

 

 

Segment

 

2013

 

2012

 

Change

 

 

 

(in thousands)

 

Crude oil logistics

 

$

12,493

 

$

5,819

 

$

6,674

 

Water services

 

5,956

 

4,547

 

1,409

 

Natural gas liquids logistics

 

12,490

 

11,402

 

1,088

 

Retail propane

 

(6,024

)

(6,640

)

616

 

Corporate and other

 

(22,312

)

(11,617

)

(10,695

)

Operating income

 

$

2,603

 

$

3,511

 

$

(908

)

 

The operating loss within “corporate and other” for the six months ended September 30, 2013 includes approximately $10.3 million of expense related to equity-based compensation, approximately $1.4 million of expenses related to acquisitions, and approximately $10.4 million of other corporate expenses.

 

The operating loss within “corporate and other” for the six months ended September 30, 2012 includes approximately $3.0 million of expense related to equity-based compensation, approximately $4.4 million of expenses related to acquisitions, and approximately $4.7 million of other corporate expenses.

 

The increase in equity-based compensation is due in part to the timing of the grants and is also due in part to an increase in the market value of our common units. Most of the restricted unit awards were granted in June 2012 and December 2012, and the expense is recorded over the vesting period of the awards. The expense is adjusted during the vesting period based on the market value of the common units on the reporting date. The value of the common units was higher at September 30, 2013 than at September 30, 2012.

 

The decrease in acquisition-related expenses is due primarily to the fact that $3.7 million of expense was recorded during the six months ended September 30, 2012 related to the merger with High Sierra.

 

The increase in other corporate expenses is due primarily to increases in compensation expense, due to the addition of new corporate employees to provide general and administrative services in support of the growth of our business.

 

The operations of our compressor leasing business are also included within “corporate and other.”

 

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Table of Contents

 

Crude Oil Logistics

 

The following table summarizes the operating results of our crude oil logistics segment for the six months ended September 30, 2013 and 2012 (amounts in thousands).

 

 

 

Six Months Ended

 

 

 

 

 

September 30,

 

 

 

 

 

2013

 

2012

 

Change

 

Revenues:

 

 

 

 

 

 

 

Crude oil sales

 

$

1,941,595

 

$

785,677

 

$

1,155,918

 

Other revenues

 

19,729

 

2,534

 

17,195

 

Total revenues(1)

 

1,961,324

 

788,211

 

1,173,113

 

Expenses:

 

 

 

 

 

 

 

Cost of sales

 

1,917,876

 

774,243

 

1,143,633

 

Operating expenses

 

21,175

 

5,426

 

15,749

 

General and administrative expenses

 

1,766

 

783

 

983

 

Depreciation and amortization expense

 

8,014

 

1,940

 

6,074

 

Total expenses

 

1,948,831

 

782,392

 

1,166,439

 

 

 

 

 

 

 

 

 

Segment operating income

 

$

12,493

 

$

5,819

 

$

6,674

 

 


(1)         Revenues include $16.5 million of intersegment sales during the six months ended September 30, 2013 and $3.7 million of intersegment sales during the six months ended September 30, 2012 that are eliminated in our consolidated statements of operations.

 

Revenues. Revenues from crude oil sales increased approximately $1.2 billion during the six months ended September 30, 2013, as compared to revenues from sales of crude oil of $785.7 million during the six months ended September 30, 2012. This resulted from an increase in volume sold of 10.1 million barrels, as compared to 8.5 million barrels sold during the six months ended September 30, 2012, and to an increase in the average sales price of $11.89 per barrel, compared to an average sales price per barrel of $92.86 during the six months ended September 30, 2012. The increase in volume sold is due in part to the fact that we did not own a crude oil logistics business for the full six months ended September 30, 2012, as we did not own this business until our June 19, 2012 merger with High Sierra. The increase is volume is also due to subsequent acquisitions of crude oil logistics businesses, including Pecos and Third Coast, among others.

 

Other revenues include transportation and terminalling fees. These revenues increased by $17.2 million during the six months ended September 30, 2013, as compared to revenues of $2.5 million during the six months ended September 30, 2012. The increase in other revenues is due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and is also due in part to subsequent acquisitions of crude oil logistics businesses.

 

Cost of Sales. Cost of crude oil sold increased approximately $1.1 billion during the six months ended September 30, 2013, as compared to cost of crude oil sold of $774.2 million during the six months ended September 30, 2012. This resulted from an increase in volume sold of 10.1 million barrels, as compared to 8.5 million barrels sold during the six months ended September 30, 2012, and to an increase in the average cost of $11.96 per barrel, compared to an average cost per barrel of $91.51 during the six months ended September 30, 2012. During the six months ended September 30, 2013, cost of sales was increased by $1.8 million of realized losses on derivatives, which was partially offset by $1.5 million of unrealized gains on derivatives. During the six months ended September 30, 2012, cost of sales was increased by $8.2 million of realized losses on derivatives, which was partially offset by $2.0 million of unrealized gains on derivatives.

 

Operating Expenses. Operating expenses of our crude oil logistics segment increased approximately $15.7 million during the six months ended September 30, 2013, compared to operating expenses of $5.4 million during the six months ended September 30, 2012. This increase is due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and is also due in part to subsequent acquisitions of crude oil logistics businesses.

 

General and Administrative Expenses. General and administrative expenses of our crude oil logistics segment increased approximately $1.0 million during the six months ended September 30, 2013, compared to general and administrative expenses of $0.8 million during the six months ended September 30, 2012. This increase is due primarily to the fact that we did not own a crude

 

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oil logistics business until our June 19, 2012 merger with High Sierra, and is also due in part to subsequent acquisitions of crude oil logistics businesses.

 

Depreciation and Amortization Expense. Depreciation and amortization expense of our crude oil logistics segment increased approximately $6.1 million during the six months ended September 30, 2013, compared to depreciation and amortization expense of $1.9 million during the six months ended September 30, 2012. This increase is due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and is also due in part to subsequent acquisitions of crude oil logistics businesses.

 

Operating Income. Operating income of our crude oil logistics segment was higher during the six months ended September 30, 2013 than during the six months ended September 30, 2012. Acquisitions of business contributed to operating income during the three months ended September 30, 2013, although this benefit was partially offset by a narrowing of price differences between markets, which reduced our opportunities to generate increased margins by transporting product from lower-price to higher-price markets.

 

Water Services

 

The following table summarizes the operating results of our water services segment for the six months ended September 30, 2013 and 2012 (amounts in thousands).

 

 

 

Six Months Ended

 

 

 

 

 

September 30,

 

Change

 

 

 

2013

 

2012

 

Acquisitions (1)

 

Other

 

Revenues:

 

 

 

 

 

 

 

 

 

 

Water treatment and disposal

 

$

47,511

 

$

14,236

 

$

23,295

 

$

9,980

 

Water transportation

 

7,192

 

3,515

 

3,873

 

(196

)

Total revenues

 

54,703

 

17,751

 

27,168

 

9,784

 

Expenses:

 

 

 

 

 

 

 

 

 

Cost of sales

 

4,365

 

2,670

 

2,419

 

(724

)

Operating expenses

 

24,010

 

6,958

 

13,648

 

3,404

 

General and administrative expenses

 

1,578

 

526

 

278

 

774

 

Depreciation and amortization expense

 

18,794

 

3,050

 

5,628

 

10,116

 

Total expenses

 

48,747

 

13,204

 

21,973

 

13,570

 

 

 

 

 

 

 

 

 

 

 

Segment operating income

 

$

5,956

 

$

4,547

 

$

5,195

 

$

(3,786

)

 


(1)   Represents the change in revenues and expenses attributable to acquisitions subsequent to the merger with High Sierra.

 

Revenues. Water treatment and disposal revenues of our water services segment increased approximately $33.3 million during the six months ended September 30, 2013, compared to water treatment and disposal revenues of $14.2 million during the six months ended September 30, 2012. This was due primarily to an increase in volume delivered of 19.7 million barrels, compared to 6.8 million barrels during the six months ended September 30, 2012. The increase in volume of water delivered is due primarily to the fact that we did not own a water services business until our June 19, 2012 merger with High Sierra and due also to subsequent acquisitions of water services businesses. The average revenue per barrel processed declined approximately $0.31 per barrel, as compared to revenue per barrel processed of $2.10 during the six months ended September 30, 2012. The expansion of our water services business subsequent to our merger with High Sierra has been primarily in Texas, where the market rates for water disposal services are typically lower than in Wyoming or Colorado.

 

Water transportation revenues increased $3.7 million during the six months ended September 30, 2013, compared to revenues of $3.5 million during the six months ended September 30, 2012. This increase was due primarily to the August 2, 2013 acquisition of OWL.

 

Cost of Sales. Cost of sales increased by approximately $1.7 million during the six months ended September 30, 2013, as compared to cost of sales of $2.7 million during the six months ended September 30, 2012. The increase was due primarily to the expansion of our operations through acquisitions. This was partially offset by the fact that cost of sales during the six months ended

 

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September 30, 2013 were reduced by $0.3 million of unrealized gains on derivatives, whereas costs of sales during the six months ended September 30, 2012 were increased by $1.3 million of unrealized losses on derivatives.

 

Operating Expenses. Operating expenses of our water services segment increased approximately $17.1 million during the six months ended September 30, 2013, compared to operating expenses of $7.0 million during the six months ended September 30, 2012. This increase is due primarily to the fact that we did not own a water services business until our June 19, 2012 merger with High Sierra, and is also due in part to subsequent acquisitions of water services businesses. We incurred losses on disposal of property, plant and equipment of $2.0 million during the three months ended September 30, 2013 as a result of property damage resulting from lightning strikes at two of our facilities.

 

General and Administrative Expenses. General and administrative expenses of our water services segment increased approximately $1.1 million during the six months ended September 30, 2013, compared to general and administrative expenses of $0.5 million during the six months ended September 30, 2012. This increase is due in part to the fact that we did not own a water services business until our June 19, 2012 merger with High Sierra, and is also due in part to subsequent acquisitions of water services businesses.

 

Depreciation and Amortization Expense. Depreciation and amortization expense of our water services segment increased approximately $15.7 million during the six months ended September 30, 2013, compared to depreciation and amortization expense of $3.1 million during the six months ended September 30, 2012. This increase is due in part to the fact that we did not own a water services business until our June 19, 2012 merger with High Sierra, and is also due in part to subsequent acquisitions of water services businesses.

 

Operating Income. Operating income of our water services segment increased approximately $1.4 million during the six months ended September 30, 2013, compared to operating income of $4.5 million during the six months ended September 30, 2012. This was due to expanded operations through acquisitions, partially offset by losses of $2.0 million during the six months ended September 30, 2013 as a result of property damage resulting from lightning strikes at two of our facilities and also partially offset by increased depreciation and amortization expense.

 

Natural Gas Liquids Logistics

 

The following table summarizes the operating results of our natural gas liquids logistics segment for the six months ended September 30, 2013 and 2012 (amounts in thousands).

 

 

 

Six Months Ended

 

 

 

 

 

September 30,

 

 

 

 

 

2013

 

2012

 

Change

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Propane sales

 

$

315,274

 

$

222,824

 

$

92,450

 

Other natural gas liquids sales

 

558,459

 

339,762

 

218,697

 

Other revenues

 

18,114

 

8,321

 

9,793

 

Total revenues (1)

 

891,847

 

570,907

 

320,940

 

 

 

 

 

 

 

 

 

Expenses:

 

 

 

 

 

 

 

Cost of sales - propane

 

302,108

 

208,161

 

93,947

 

Cost of sales - other NGLs

 

541,077

 

327,951

 

213,126

 

Cost of sales - storage

 

12,474

 

5,138

 

7,336

 

Operating expenses

 

15,532

 

10,506

 

5,026

 

General and administrative expenses

 

2,790

 

2,299

 

491

 

Depreciation and amortization expense

 

5,376

 

5,450

 

(74

)

Total expenses

 

879,357

 

559,505

 

319,852

 

 

 

 

 

 

 

 

 

Segment operating income

 

$

12,490

 

$

11,402

 

$

1,088

 

 


(1)         Revenues include $46.0 million of intersegment sales during the six months ended September 30, 2013 and $28.9 million of intersegment sales during the six months ended September 30, 2012 that are eliminated in our consolidated statements of operations.

 

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Revenues. Revenues from wholesale propane sales increased approximately $92.5 million during the six months ended September 30, 2013, compared to wholesale propane sales of $222.8 million during the six months ended September 30, 2012. This resulted from an increase in the volume sold of 54.1 million gallons, compared to 256.8 million gallons sold during the six months ended September 30, 2012, and to an increase in the price per gallon sold of approximately $0.14, compared to an average price per gallon sold of $0.87 during the six months ended September 30, 2012. Approximately 17.6 million gallons of the increase in volume sold was due to the fact that we only owned the natural gas liquids business of High Sierra for a part of the six months ended September 30, 2012. The remaining increase in volume is due to several factors. Market demand was higher, due in part to colder weather conditions. Volumes also increased due to the expansion of our sales staff. In addition, during the year ended March 31, 2013, we refurbished two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

 

Revenues from wholesale sales of other natural gas liquids increased approximately $218.7 million during the six months ended September 30, 2013, compared to sales of $339.8 million during the six months ended September 30, 2012. This resulted from an increase in the volume sold of 292.3 million gallons, compared to 251.8 million gallons sold during the six months ended September 30, 2012, partially offset by a decrease in the price per gallon sold of approximately $0.32, compared to an average price per gallon sold of $1.35 during the six months ended September 30, 2012. Approximately 169.5 million gallons of the increase in volume sold was due to the fact that we only owned the natural gas liquids business of High Sierra for a part of the six months ended September 30, 2012. The remaining increase in volume is due to several factors. Market demand for butane to be used in gasoline blending operations was higher. Volumes also increased due to the expansion of our sales staff and to an increased focus on the opportunity to more fully utilize our terminals to market butane.

 

Cost of Sales. Cost of wholesale propane sales increased approximately $93.9 million during the six months ended September 30, 2013, compared to cost of wholesale propane sales of $208.2 million during the six months ended September 30, 2012. This resulted from an increase in the volume sold of 54.1 million gallons, compared to 256.8 million gallons sold during the six months ended September 30, 2012, and to an increase in the cost per gallon sold of approximately $0.16, compared to an average cost per gallon sold of $0.81 during the six months ended September 30, 2012. Cost per gallon sold during the six months ended September 30, 2013 included $5.2 million of unrealized losses on derivatives, which was partially offset by $2.3 million of realized gains on derivatives. Cost per gallon sold during the six months ended September 30, 2012 was reduced by $11.1 million of unrealized gains and $2.2 million of realized gains on derivatives.

 

Declining wholesale propane prices during the first quarter of the prior fiscal year had an adverse effect on cost of sales during the six months ended September 30, 2012. Our wholesale segment utilizes a weighted-average inventory costing method to calculate cost of sales. Propane prices decreased steadily during April and May 2012, as a result of which the replacement cost of propane was at times lower than the weighted-average cost, which had an adverse effect on margins. One of our business strategies is to purchase and store inventory during the warmer months for sale during the winter months. We seek to lock in a margin on inventory held in storage through back-to-back purchases and sales, fixed-price forward sale commitments, and financial derivatives. We also have contracts whereby we have committed to purchase ratable volumes each month at index prices. We seek to manage the price risk associated with these contracts primarily by selling the inventory immediately after it is received. When we sell product, we record the cost of the sale at the average cost of all inventory at that location, which may include inventory stored for sale in the future. During periods of rising prices, this can result in greater margins on these sales. During periods of falling prices, such as we experienced during the three months ended June 30, 2012, this can result in negative margins on these sales, which we recovered when delivering future volumes.

 

Cost of wholesale sales of other natural gas liquids increased approximately $213.1 million during the six months ended September 30, 2013, compared to cost of sales of $328.0 million during the six months ended September 30, 2012. This resulted from an increase in the volume sold of 292.3 million gallons, compared to 251.8 million gallons sold during the six months ended September 30, 2012, partially offset by a decrease in the cost per gallon sold of approximately $0.31, compared to an average cost per gallon sold of $1.30 during the six months ended September 30, 2012. Cost of sales of other natural gas liquids during the six months ended September 30, 2013 included $13.5 million of realized losses and $0.3 million of unrealized losses on derivatives. Cost of sales of other natural gas liquids during the six months ended September 30, 2012 included $1.3 million of unrealized losses and $0.1 million of realized losses on derivatives.

 

Operating Expenses. Operating expenses of our natural gas liquids logistics segment increased approximately $5.0 million during the six months ended September 30, 2013, compared to operating expenses of $10.5 million during the six months ended September 30, 2012, due to expanded operations.

 

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General and Administrative Expenses. General and administrative expenses of our natural gas liquids logistics segment increased approximately $0.5 million during the six months ended September 30, 2013, compared to general and administrative expenses of $2.3 million during the six months ended September 30, 2012.

 

Depreciation and Amortization Expense. Depreciation and amortization expense of our natural gas liquids logistics segment decreased approximately $0.1 million during the six months ended September 30, 2013, compared to depreciation and amortization expense of $5.5 million during the six months ended September 30, 2012.

 

Operating Income. Operating income of our natural gas liquids logistics segment increased approximately $1.1 million during the six months ended September 30, 2013, compared to operating income of $11.4 million during the six months ended September 30, 2012.

 

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Retail Propane

 

The following table summarizes the operating results of our retail propane segment for the six months ended September 30, 2013 and 2012 (amounts in thousands).

 

 

 

Six Months Ended

 

 

 

 

 

September 30,

 

 

 

 

 

2013

 

2012

 

Change

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Propane sales

 

$

87,342

 

$

77,791

 

$

9,551

 

Distillate sales

 

28,431

 

22,623

 

5,808

 

Other revenues

 

15,898

 

15,797

 

101

 

Total revenues

 

131,671

 

116,211

 

15,460

 

Expenses:

 

 

 

 

 

 

 

Cost of sales - propane

 

47,027

 

42,489

 

4,538

 

Cost of sales - distillates

 

24,509

 

18,897

 

5,612

 

Cost of sales - other

 

5,100

 

5,721

 

(621

)

Operating expenses

 

41,839

 

39,068

 

2,771

 

General and administrative expenses

 

5,109

 

4,748

 

361

 

Depreciation and amortization expense

 

14,111

 

11,928

 

2,183

 

Total expenses

 

137,695

 

122,851

 

14,844

 

 

 

 

 

 

 

 

 

Segment operating loss

 

$

(6,024

)

$

(6,640

)

$

616

 

 

Revenues. Propane sales for the six months ended September 30, 2013 increased approximately $9.6 million, compared to $77.8 million of propane sales during the six months ended September 30, 2012. Propane sales revenues were higher during the six months ended September 30, 2013 than during the six months ended September 30, 2012, due primarily to an increase in volume sold of 4.7 million gallons, compared to 39.3 million gallons sold during the six months ended September 30, 2012. The increase in volume sold was due primarily to colder weather conditions. The average price per gallon sold increased by $0.01, compared to an average price per gallon sold of $1.98 during the six months ended September 30, 2012.

 

Distillate sales for the six months ended September 30, 2013 increased approximately $5.8 million as compared to distillate sales of $22.6 million during the six months ended September 30, 2012, primarily due to an increase in the volume sold of 1.9 million gallons, as compared to a volume sold of 6.3 million gallons in the prior year. This increase in volume was due primarily to the fact that we acquired Downeast on May 1, 2012, and Downeast was only included in our results of operations for five of the months in the six month period ended September 30, 2012. The increase in revenues resulting from the increase in sales volume was partially offset by a decrease in the average price per gallon sold of $0.13, compared to an average price per gallon sold of $3.61 during the six months ended September 30, 2012.

 

Cost of Sales. Propane cost of sales for the six months ended September 30, 2013 increased approximately $4.5 million, compared to $42.5 million during the six months ended September 30, 2012. This increase was due primarily to an increase in the volume sold of 4.7 million gallons, compared to 39.3 million gallons sold during the six months ended September 30, 2012. The average cost per gallon sold decreased by $0.01 per gallon, compared to an average cost per gallon sold of $1.08 during the six months ended September 30, 2012.

 

Distillate cost of sales for the six months ended September 30, 2013 increased approximately $5.6 million, compared to $18.9 million during the six months ended September 30, 2012. This increase was due primarily to an increase in the volume sold of 1.9 million gallons, compared to 6.3 million gallons sold during the six months ended September 30, 2012. The average cost per gallon sold decreased by $0.01 per gallon, compared to an average cost per gallon sold of $3.01 during the six months ended September 30, 2012. Cost of distillate sales during the six months ended September 30, 2012 were reduced by $0.9 million of unrealized gains on derivatives.

 

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Operating Expenses. Operating expenses of our retail propane segment increased approximately $2.8 million during the six months ended September 30, 2013, compared to operating expenses of $39.1 million during the six months ended September 30, 2012. This increase was due in part to the inclusion of Downeast in our results of operations for the full six months ended September 30, 2013, as compared to only five of the months in the six month period ended September 30, 2012.

 

General and Administrative Expenses. General and administrative expenses of our retail propane segment increased approximately $0.4 million during the six months ended September 30, 2013, compared to general and administrative expenses of $4.7 million during the six months ended September 30, 2012. This increase was due in part to the inclusion of Downeast in our results of operations for the full six months ended September 30, 2013, as compared to only five of the months in the six month period ended September 30, 2012.

 

Depreciation and Amortization Expense. Depreciation and amortization expense of our retail propane segment increased approximately $2.2 million during the six months ended September 30, 2013, compared to depreciation and amortization expense of $11.9 million during the six months ended September 30, 2012. This increase was due in part to the inclusion of Downeast in our results of operations for the full six months ended September 30, 2013, as compared to only five of the months in the six month period ended September 30, 2012.

 

Operating Loss. Operating loss of our retail propane segment decreased approximately $0.6 million during the six months ended September 30, 2013, compared to an operating loss of $6.6 million during the six months ended September 30, 2012.

 

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 significantly during the year due to the seasonal nature of our 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 natural gas liquids logistics operations are the greatest.

 

Under our partnership agreement, we are required to make distributions in an amount equal to all of our available cash, if any, no more than 45 days after the end of each fiscal quarter to holders of record on the applicable record dates. Available cash generally means all cash on hand at the end of the respective fiscal quarter less the amount of cash reserves established by our general partner in its reasonable discretion for future cash requirements. These reserves are retained for the proper conduct of our business, debt principal and interest payments and for distributions to our unitholders during the next four quarters. Our general partner reviews the level of available cash on a quarterly basis based upon information provided by management.

 

We believe that our anticipated cash flows from operations and the borrowing capacity under our Credit Agreement (as defined below) 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.

 

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 equity to sellers of the businesses we acquire, private placements of common units or debt securities, and public offerings of common units or debt 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.

 

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Credit Agreement

 

On June 19, 2012, we 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”). The Working Capital Facility had a total capacity of $325.0 million for cash borrowings and letters of credit at September 30, 2013. At September 30, 2013, we had outstanding cash borrowings of $229.5 million and outstanding letters of credit of $85.9 million on the Working Capital Facility, leaving a remaining capacity of $9.6 million at September 30, 2013. The Expansion Capital Facility had a total capacity of $725.0 million for cash borrowings at September 30, 2013. At September 30, 2013, we had outstanding cash borrowings of $416.5 million on the Expansion Capital Facility, leaving a remaining capacity of $308.5 million at September 30, 2013. The capacity available under the Working Capital Facility may be limited by a “borrowing base,” as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time. At September 30, 2013, the borrowing base provisions of the Credit Agreement did not have any impact on the capacity available under the Working Capital Facility.

 

The commitments under the Credit Agreement expire on June 19, 2017. We have the right to pre-pay outstanding borrowings under the Credit Agreement without incurring any penalties, and pre-payments 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 (i) an alternate base rate plus a margin of 1.75% to 2.75% per annum or (ii) an adjusted LIBOR rate plus a margin of 2.75% to 3.75% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At September 30, 2013, the interest rate in effect on outstanding LIBOR borrowings was 3.19%, calculated as the LIBOR rate of 0.19% plus a margin of 3.0%. At September 30, 2013, the interest rate in effect on outstanding base rate borrowings was 5.25%, calculated as the base rate of 3.25% plus a margin of 2.0%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. At September 30, 2013, our outstanding borrowings and interest rates under our Revolving Credit Facility were as follows (dollars in thousands):

 

 

 

Amount

 

Rate

 

Expansion Capital Facility —

 

 

 

 

 

LIBOR borrowings

 

$

416,500

 

3.19

%

Working Capital Facility —

 

 

 

 

 

LIBOR borrowings

 

204,000

 

3.18

%

Base rate borrowings

 

25,500

 

5.25

%

 

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 1.0 at any quarter end. At September 30, 2013, our leverage ratio was less than 2.5 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 as of the last day of any fiscal quarter. At September 30, 2013, our interest coverage ratio was greater than 7.5 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, 2013, we were in compliance with all covenants under the Credit Agreement.

 

As described above under “Recent Developments”, we entered into an amendment to the Credit Agreement during November 2013. This amendment increased the capacity on the Expansion Capital and Working Capital facilities, extended the maturity date of the Credit Agreement, and reduced the interest rate on LIBOR rate borrowings.

 

Senior Notes

 

Also on June 19, 2012, we entered into a note purchase agreement (the “Note Purchase Agreement”) whereby we issued $250 million of Senior Notes in a private placement (the “Senior Notes”). The Senior Notes have an aggregate principal amount of $250.0 million and bear interest at a fixed rate of 6.65%. Interest is payable quarterly. The Senior 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 pre-pay outstanding principal, although we would incur a pre-payment penalty. The Senior Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

 

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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 or merge or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains the same leverage ratio and interest coverage ratio requirements as our Credit Agreement, which are 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) non-payment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the Senior Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10 million, (iv) the rendering of a judgment for the payment of money in excess of $10 million, (v) the failure of the Note Purchase Agreement, the Senior 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 Senior Notes of any series may declare all of the Senior Notes of such series to be due and payable immediately.

 

At September 30, 2013, we were in compliance with all covenants under the Note Purchase Agreement and the Senior Notes.

 

Senior Unsecured Notes

 

As described above under “Recent Developments”, we issued $450.0 million of senior unsecured notes during October 2013. These senior unsecured notes bear interest at a fixed rate of 6.875% and mature on October 15, 2021.

 

Previous Credit Facilities

 

On June 19, 2012, we made a principal payment of $306.8 million to retire our previous revolving credit facility. Upon retirement of this facility, we wrote off the portion of the debt issuance cost asset that had not yet been amortized. This expense is reported as “Loss on early extinguishment of debt” in our consolidated statement of operations for the six months ended September 30, 2012.

 

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Revolving Credit Balances

 

The following table provides certain information on revolving credit facility borrowings during the six months ended September 30, 2013 and 2012 (dollars in thousands):

 

 

 

Daily Average

 

Lowest

 

Highest

 

 

 

Balance

 

Balance

 

Balance

 

Six Months Ended September 30, 2013:

 

 

 

 

 

 

 

Expansion loans

 

$

440,423

 

$

255,000

 

$

546,000

 

Working capital loans

 

80,779

 

 

229,500

 

 

 

 

 

 

 

 

 

Six Months Ended September 30, 2012:

 

 

 

 

 

 

 

New credit facility (June 19 - September 30) —

 

 

 

 

 

 

 

Expansion loans

 

$

256,385

 

$

254,000

 

$

262,000

 

Working capital loans

 

106,322

 

70,000

 

139,000

 

Previous credit facility (April 1 - June 19) —

 

 

 

 

 

 

 

Acquisition loans

 

222,238

 

186,000

 

239,275

 

Working capital loans

 

42,700

 

22,000

 

67,500

 

 

Cash Flows

 

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

 

 

 

Six Months Ended September 30,

 

Cash Flows Provided by (Used In):

 

2013

 

2012

 

 

 

 

 

 

 

Operating activities, before changes in operating assets and liabilities

 

$

60,976

 

$

14,960

 

Changes in operating assets and liabilities

 

(109,317

)

(67,766

)

 

 

 

 

 

 

Operating activities

 

$

(48,341

)

$

(52,806

)

 

 

 

 

 

 

Investing activities

 

(477,257

)

(309,977

)

 

 

 

 

 

 

Financing activities

 

519,565

 

380,960

 

 

Operating Activities. The seasonality of our natural gas liquids businesses has a significant effect on our cash flows from operating activities. The changes in our operating assets and liabilities caused by the seasonality of our retail and wholesale natural gas liquids businesses also have a significant impact on our net cash flows from operating activities. Increases in natural gas liquids prices will tend to result in reduced operating cash flows due to the need to use more cash to fund increases in inventories, and price decreases tend to increase our operating cash flow 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 less 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 needed during our first and second quarters.

 

Investing Activities. Our cash flows from investing activities are primarily impacted by our capital expenditures. In periods where we are engaged in significant acquisitions, we will generally realize negative cash flows in investing activities, which, depending on our cash flows from operating activities, may require us to increase the borrowings under our Revolving Credit Facility.

 

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During the six months ended September 30, 2013, we completed a number of business combinations for which we paid $393.0 million of cash, net of cash acquired, on a combined basis. Also during the six months ended September 30, 2013, we paid $67.4 million for capital expenditures, which related primarily to water disposal and natural gas liquids terminal assets. Of this amount, approximately $52.4 million represented expansion capital and approximately $15.0 million represented maintenance capital.

 

During the six months ended September 30, 2012, we completed our merger with High Sierra, for which we paid $239.3 million, net of cash acquired. Also, during the six months ended September 30, 2012, we completed five other acquisitions, for which we paid $67.8 million of cash, net of cash acquired, on a combined basis.

 

Financing Activities. Changes in our cash flow from financing activities include advances from and repayments on our revolving credit facilities, either to fund our operating or investing requirements. In periods where our cash flows from operating activities are reduced (such as during our first and second quarters), we may fund the cash flow deficits through our Working Capital Facility. During the six months ended September 30, 2013, we borrowed $168.5 million on our Revolving Credit Facility (net of repayments). During the six months ended September 30, 2012, we borrowed $172.0 million on our revolving credit facilities (net of repayments) and issued $250.0 million of Senior Notes. During the six months ended September 30, 2012, we paid $17.8 million of debt issuance costs.

 

Cash flows from financing activities include proceeds from sales of equity. During the six months ended September 30, 2013, we completed two equity offerings for which we received net proceeds of $415.1 million on a combined basis.

 

Cash flows from financing activities also include distributions paid to owners. We expect our distributions to our partners to increase in future periods under the terms of our partnership agreement. Based on the number of common and subordinated units outstanding at September 30, 2013 (exclusive of unvested restricted units issued pursuant to employee and director compensation programs), if we made distributions equal to our minimum quarterly distribution of $0.3375 per unit ($1.35 annualized), total distributions would equal $24.1 million per quarter ($96.2 million per year). To the extent our cash flows from operating activities are not sufficient to finance our required distributions, we may be required to increase the borrowings under our Working Capital Facility.

 

The following table summarizes the distributions declared since 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 18, 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

 

 

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Contractual Obligations

 

The following table updates our contractual obligations summary as of September 30, 2013 for our fiscal years ending thereafter (amounts in thousands):

 

 

 

 

 

For the

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months

 

 

 

 

 

 

 

 

 

 

 

 

 

Ending

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

For the Years Ending March 31,

 

After March 31,

 

 

 

Total

 

2014

 

2015

 

2016

 

2017

 

2017

 

 

 

(in thousands)

 

Principal payments on long-term debt

 

 

 

 

 

 

 

 

 

 

 

 

 

Expansion capital borrowings

 

$

416,500

 

$

 

$

 

$

 

$

 

$

416,500

 

Working capital borrowings

 

229,500

 

 

 

 

 

229,500

 

Senior notes

 

250,000

 

 

 

 

 

250,000

 

Other long-term debt

 

18,295

 

5,780

 

6,913

 

3,186

 

1,888

 

528

 

Interest payments on long-term debt —

 

 

 

 

 

 

 

Revolving credit facility (1)

 

92,540

 

12,411

 

24,891

 

24,891

 

24,891

 

5,456

 

Senior notes

 

108,063

 

8,313

 

16,625

 

16,625

 

16,625

 

49,875

 

Other long-term debt

 

1,090

 

273

 

388

 

211

 

118

 

100

 

Standby letters of credit

 

85,916

 

 

 

 

 

85,916

 

Future minimum lease payments under noncancelable operating leases

 

291,508

 

31,924

 

51,652

 

46,720

 

44,174

 

117,038

 

Fixed price commodity purchase commitments

 

74,356

 

74,356

 

 

 

 

 

Index priced commodity purchase commitments (2)

 

1,232,676

 

1,075,094

 

128,858

 

28,724

 

 

 

Total contractual obligations

 

$

2,800,444

 

$

1,208,151

 

$

229,327

 

$

120,357

 

$

87,696

 

$

1,154,913

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas liquids gallons under fixed-price purchase commitments (thousands) (3)

 

79,041

 

79,041

 

 

 

 

 

Natural gas liquids gallons under index-price purchase commitments (thousands) (3)

 

653,808

 

593,952

 

59,856

 

 

 

 

Crude oil barrels under index-price purchase commitments (thousands) (3)

 

4,963

 

3,918

 

688

 

357

 

 

 

 


(1)         The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at September 30, 2013. See Note 7 to our consolidated financial statements included elsewhere herein for additional information on our Credit Agreement.

(2)         Index prices are based on a forward price curve as of September 30, 2013. A theoretical change of $0.10 per gallon in the underlying commodity price at September 30, 2013 would result in a change of approximately $65.4 million in the value of our index-based natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel in the underlying commodity price at September 30, 2013 would result in a change of approximately $5.0 million in the value of our index-based crude oil purchase commitments.

(3)         At September 30, 2013, we had fixed priced and index-price sales contracts for approximately 146.4 million and 464.2 million gallons of natural gas liquids, respectively. At September 30, 2013, we had index-price sales contracts for approximately 4.6 million barrels of crude oil.

 

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Off-Balance Sheet Arrangements

 

We do not have any off balance sheet arrangements other than the operating leases described in Note 9 to the financial statements included elsewhere in this quarterly report.

 

Environmental Legislation

 

Please see our Annual Report on Form 10-K for the year ended March 31, 2013 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 Logistics

 

Crude oil prices fluctuate widely, due to 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. Currently, production of crude oil in North America is high. Changes in the level of production could impact our ability to generate revenues in the future.

 

In addition, the spread between the prices of crude oil in different locations can also fluctuate widely. If these price differences are high, we are able to generate higher margins by transporting crude oil from lower-price markets to higher-price markets. During the fiscal year ended March 31, 2013, the spread between crude oil prices in the mid-continent region and crude oil prices in south Texas widened, which gave us the opportunity to generate favorable margins by transporting crude oil from one region to the other. This spread narrowed considerably during the six months ended September 30, 2013.

 

Water Services

 

Our opportunity to earn revenues in our water services business is based on the level of production of natural gas and crude oil in the areas where our facilities are located. Recently, production has been strong in most of these regions. A future decline in the level of production could have an adverse impact on profitability.

 

During the three months ended September 30, 2013, we completed three separate acquisitions of water services businesses with operations in Texas. As a result, the geographic mix of our water services segment has changed, and we expect a greater share of the revenues from this segment to be generated from our operations in the Permian and Eagle Ford Basins than in the past.

 

Our facility in Wyoming and two of our facilities in Colorado have the capability to process wastewater to the point where it can be returned to the producer for use in future drilling operations. We typically generate additional profits from this activity. Future changes in customer attitudes or in the regulatory climate could provide future opportunities for us to generate increased profits from these activities.

 

Natural Gas Liquids Logistics

 

The volumes we sell in our wholesale natural gas liquids business are heavily dependent on the demand for propane and butane, which is influenced by weather conditions. During the most recent winter weather conditions were relatively mild, and the preceding winter was one of the warmest on record, which reduced demand and resulted in lower prices for natural gas liquids. The margins we generate in our wholesale natural gas liquids business are influenced by changes in prices over the course of a year. During years when demand is higher during the winter months, we have the opportunity to utilize our storage assets to increase margins.

 

Retail Propane

 

The volumes we sell in our retail propane business are heavily dependent on weather conditions, as cold weather significantly increases customer demand for propane. During times of lower propane prices, such as we have experienced over the two most recent years, margins per gallon typically increase. During times of higher propane prices, such as we may experience in the future, margins per gallon typically decrease.

 

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Critical Accounting Policies

 

The preparation of financial statements and related disclosures in compliance 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 critical accounting policies that are most important to the portrayal of our financial condition and results of operations. Changes in these policies could have a material effect on the financial statements.

 

The application of these accounting policies necessarily requires our most subjective or complex judgments regarding estimates and projected outcomes of future events which could have a material impact on the financial statements.

 

Revenue Recognition

 

We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. We record terminaling, storage and service revenues at the time the service is performed and we record tank and other rentals over the term of the lease. Revenues for the wastewater disposal business are recognized upon receipt of the wastewater at our disposal facilities.

 

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. Amounts billed to customers for shipping and handling costs are included in revenues in the consolidated statements of operations. Shipping and handling costs associated with product sales are included in operating expenses in the consolidated statements of operations.

 

We enter into certain contracts whereby we agree to purchase product from a counterparty and to sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into concurrently and are entered into in contemplation of each other, we record the revenues for these transactions net of the 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. We completed the assessment of each of our reporting units and determined no impairment existed for the year ended March 31, 2013. 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. 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.

 

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. At September 30, 2013, we have recorded a liability of $1.8 million for obligations related to the retirement of pipeline injection facilities of our crude oil logistics business and the facilities of our water services business.

 

In addition to the pipeline injection facilities and the water processing facilities, we may be obligated by contractual or regulatory requirements to remove certain of our other assets, or perform other remediation of the sites where such assets are located, upon the retirement of those assets. However, we do not believe the present value of such asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of our facilities, is material to our financial position or results of operations.

 

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

 

Depreciation expense represents the systematic and rational write-off of the cost of our property and equipment, net of residual or salvage value (if any), to the results of operations for the quarterly and annual periods the assets are used. We depreciate the majority of our property and equipment using the straight-line method, which results in our 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. At the time we acquire and place our property and equipment in service, we develop assumptions about such lives and residual values that we believe are reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our depreciation expense amounts 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.

 

For additional information regarding our property and equipment, see Note 5 of our condensed consolidated financial statements included elsewhere in this Quarterly Report.

 

Business Combinations

 

We have made in the past, and expect to make in the future, acquisitions of other businesses. We record business combinations using a method known as the “acquisition method,” in which the assets acquired and liabilities assumed are recorded at their estimated fair values. Fair values of assets acquired and liabilities assumed are based upon available information and may involve us 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 and equipment and intangible assets, including those with indefinite lives. The excess of purchase price over the net fair value of acquired assets over the assumed liabilities is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Generally, we have up to one year from the acquisition date to finalize the identification and valuation of acquired assets and liabilities. The impact of subsequent changes to the identification of assets and liabilities may require a retroactive adjustment to our previously reported financial position and results of operations.

 

Inventory

 

Our inventory consists primarily of propane, butane, and crude oil. The market value of these commodities changes on a daily basis as supply and demand conditions change. We value our inventory using the weighted-average cost and first-in first-out methods. At the end of each fiscal year, we also perform a “lower of cost or market” analysis; if the cost basis of the inventory would not be recoverable based on market prices at the end of the year, we reduce the book value of the inventory to the recoverable amount. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail 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 writedown if we expect the market values to recover by our fiscal year end of March 31. We are unable to control changes in the market value of these commodities and are unable to determine whether writedowns will be required in future periods. In addition, writedowns at interim periods could be required if we cannot conclude that market values will recover sufficiently by our fiscal year end.

 

Product Exchanges

 

In our natural gas liquids logistics business, we frequently have exchange transactions with suppliers or customers in which we will deliver product volumes to them, or receive product volumes from them to be delivered back to us or from us in future periods, generally in the short-term (referred to as “product exchanges”). The settlements of exchange volumes are generally done through in-kind arrangements whereby settlement volumes are delivered at no cost, with the exception of location or timing differentials. Such in-kind deliveries are ongoing and can take place over several months. We estimate the value of product exchange assets and liabilities based on the weighted-average cost basis of the inventory we have delivered or will deliver on the exchange, plus or minus location differentials, which we believe represents the value of the exchange volumes at such date. Changes in product prices could impact our estimates.

 

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Item 3.                                 Quantitative and Qualitative Disclosures About Market Risk

 

Interest Rate Risk

 

As of September 30, 2013, 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. As of September 30, 2013, we had $646.0 million of outstanding borrowings under our revolving credit facility. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of approximately $0.8 million.

 

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, propane, and other natural gas liquids 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.

 

As is customary in the crude oil industry, we generally receive payment from customers for sale of crude oil on a monthly basis. As a result, receivables from individual customers in our crude oil marketing business are generally higher than the receivables from customers in our other segments.

 

We take an active role in managing and controlling commodity price and credit risks and have established control procedures, which we review on an ongoing basis. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, restrictions on product liftings, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions, as deemed appropriate. The principal counterparties associated with our operations as of September 30, 2013 were retailers, resellers, energy marketers, producers, refiners and dealers.

 

The natural gas liquids and crude oil industries are “margin-based” and “cost-plus” businesses in which gross profits depend on the differential of sales prices over supply costs. As a result, our profitability will be impacted by changes in wholesale prices of natural gas liquids and crude oil. When there are sudden and sharp increases in the wholesale cost of natural gas liquids and crude oil, we may not be able to pass on these increases to our customers through retail or wholesale prices. Natural gas liquids and crude oil are commodities and the price we pay for them can fluctuate significantly in response to supply or other market conditions. We have no control over supply or market conditions. In addition, the timing of cost increases can significantly affect our realized margins. Sudden and extended wholesale price increases could reduce our gross margins and could, if continued over an extended period of time, reduce demand by encouraging end users to conserve or convert to alternative energy sources.

 

We engage in derivative financial and other risk management transactions, including various types of forward contracts and financial derivatives to reduce the effect of price volatility on our product costs, 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. 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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Although we use derivative commodity instruments to reduce the market price risk associated with forecasted transactions, we have not accounted for such derivative commodity instruments as hedges. In addition, we do not use such derivative commodity instruments for speculative or trading purposes. As of September 30, 2013, the fair value of our unsettled commodity derivative instruments was a net liability of $5.9 million. We record the changes in fair value of these derivative commodity instruments within cost of sales. The following table summarizes the hypothetical impact on the fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands):

 

 

 

Increase

 

 

 

(Decrease)

 

 

 

To Fair Value

 

Crude oil (crude oil logistics segment)

 

$

(3,186

)

Crude oil (water services segment)

 

(6,157

)

Crude oil (natural gas liquids logistics segment)

 

(6,079

)

Propane (natural gas liquids logistics segment)

 

(4,015

)

Other natural gas liquids (natural gas liquids logistics segment)

 

3,437

 

Heating oil (retail segment)

 

4

 

 

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 Rules 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 SEC and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

 

We completed an evaluation under the supervision and with participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2013. Based on this evaluation, our principal executive officer and principal financial officer have concluded that as of September 30, 2013, 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 business combinations during the year ended March 31, 2013 and the six months ended September 30, 2013, 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, 2013 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

 

We closed several business combinations during the year ended March 31, 2013 and during the six months ended September 30, 2013, as described in Note 1 to our consolidated financial statements included in this Quarterly Report on Form 10-Q. At this time, we continue to evaluate the business and internal controls and processes of these acquired businesses and are making various changes to their operating and organizational structure based on our business plan. We are in the process of implementing our internal control structure over these acquired businesses. We expect that our evaluation and integration efforts related to those combined operations will continue into future fiscal quarters, due to the magnitude of those businesses.

 

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PART II

 

Item 1.                                 Legal Proceedings

 

For information related to legal proceedings, please see the discussion under the captions “Legal Contingencies” and “Customer Dispute” in Note 9 to our unaudited condensed consolidated financial statements in Part I, Item I 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 from the risk factors previously disclosed in “Item 1A — Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended March 31, 2013.

 

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

 

During the three months ended September 30, 2013, we completed three acquisitions in which we issued unregistered common units as part of the consideration for the acquisitions. All of these units were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended, as the units were issued to the owners of businesses acquired in privately negotiated transactions not involving any public offering or solicitation. On July 1, 2013, we issued 175,211 common units to the sellers of Crescent Terminals, LLC and Cierra Marine, LP. On August 1, 2013, we issued 2,463,287 common units to the sellers of entities affiliated with Oilfield Water Lines, LP. On September 3, 2013, we issued 222,381 common units to the sellers of Coastal Plains Disposal #1, LLC.

 

Item 3.                                 Defaults Upon Senior Securities

 

Not applicable.

 

Item 4.                                 Mine Safety Disclosures

 

Not applicable.

 

Item 5.                                 Other Information

 

None.

 

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Item 6.                                 Exhibits

 

Exhibit
Number 

 

Exhibit

 

 

 

 

 

2.1

 

LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL Pearsall SWD, LLC, OWL Pearsall Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

 

2.2

 

LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL Karnes SWD, LLC, OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

 

2.3

 

LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Cotulla SWD, LLC, Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

 

2.4

 

LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Nixon SWD, LLC, Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

 

2.5

 

LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, HR OWL, LLC, OWL Operating, LLC, Lotus Oilfield Services, L.L.C., OWL Lotus, LLC, NGL Energy Partners, LP, High Sierra Water-Eagle Ford, LLC and High Sierra Transportation, LLC (incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

 

3.1

 

Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as of August 6, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

 

4.1

 

Amendment No. 7 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of August 1, 2013, by and among NGL Energy Partners LLC, Oilfield Water Lines, LP and Terry G. Bailey (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

 

4.2

 

Amendment No. 3 to Note Purchase Agreement, dated September 30, 2013, among NGL Energy Partners LP and the holders of NGL’s 6.65% senior secured notes due 2022 signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013)

 

10.1

 

Amendment No. 3 to Credit Agreement, dated September 30, 2013, among NGL Energy Partners LP, NGL Energy Operating LLC, each subsidiary of NGL identified as a “Borrower” therein, Deutsche Bank AG, New York Branch, as technical agent, Deutsche Bank Trust Company Americas, as administrative agent and collateral agent and each financial institution identified as a “Lender” or “Issuing Bank” therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013)

 

12.1

*

Ratio 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

 

 

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*                               Exhibits filed with this report.

**                        Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of September 30, 2013 and March 31, 2013, (ii) Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2013 and 2012, (iii) Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and six months ended September 30, 2013 and 2012, (iv) Condensed Consolidated Statement of Changes in Partners’ Equity for the six months ended September 30, 2013, (v) Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 2013 and 2012, 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 12, 2013

 

By:

/s/ H. Michael Krimbill

 

 

 

H. Michael Krimbill

 

 

 

Chief Executive Officer

 

 

 

 

 

 

 

 

Date: November 12, 2013

 

By:

/s/ Atanas H. Atanasov

 

 

 

Atanas H. Atanasov

 

 

 

Chief Financial Officer

 

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EXHIBIT INDEX

 

Exhibit
Number

 

Exhibit

 

 

 

2.1

 

LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL Pearsall SWD, LLC, OWL Pearsall Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

2.2

 

LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL Karnes SWD, LLC, OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

2.3

 

LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Cotulla SWD, LLC, Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

2.4

 

LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Nixon SWD, LLC, Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

2.5

 

LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, HR OWL, LLC, OWL Operating, LLC, Lotus Oilfield Services, L.L.C., OWL Lotus, LLC, NGL Energy Partners, LP, High Sierra Water-Eagle Ford, LLC and High Sierra Transportation, LLC (incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

3.1

 

Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as of August 6, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

4.1

 

Amendment No. 7 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of August 1, 2013, by and among NGL Energy Partners LLC, Oilfield Water Lines, LP and Terry G. Bailey (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

4.2

 

Amendment No. 3 to Note Purchase Agreement, dated September 30, 2013, among NGL Energy Partners LP and the holders of NGL’s 6.65% senior secured notes due 2022 signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013)

10.1

 

Amendment No. 3 to Credit Agreement, dated September 30, 2013, among NGL Energy Partners LP, NGL Energy Operating LLC, each subsidiary of NGL identified as a “Borrower” therein, Deutsche Bank AG, New York Branch, as technical agent, Deutsche Bank Trust Company Americas, as administrative agent and collateral agent and each financial institution identified as a “Lender” or “Issuing Bank” therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013)

12.1

*

Ratio 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

 

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*                                 Exhibits filed with this report.

**                         Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of September 30, 2013 and March 31, 2013, (ii) Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2013 and 2012, (iii) Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and six months ended September 30, 2013 and 2012, (iv) Condensed Consolidated Statement of Changes in Partners’ Equity for the six months ended September 30, 2013, (v) Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 2013 and 2012, and (vi) Notes to Condensed Consolidated Financial Statements.

 

76