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 June 30, 2014

 

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 No.:  0-26823 

 

 

ALLIANCE RESOURCE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware

(State or other jurisdiction of

incorporation or organization)

 

73-1564280

(IRS Employer Identification No.)

 

1717 South Boulder Avenue, Suite 400, Tulsa, Oklahoma 74119

(Address of principal executive offices and zip code)

 

(918) 295-7600

(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. [X] Yes   [   ] No

 

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

 

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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (check one)

 

Large Accelerated Filer [X]

Accelerated Filer [   ]

Non-Accelerated Filer [   ]

Smaller Reporting Company [   ]

 

 

(Do not check if smaller reporting company)

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

[   ] Yes   [X] No

 

As of August 8, 2014, 74,060,634 common units are outstanding.

 

 



Table of Contents

 

TABLE OF CONTENTS

 

PART I

 

FINANCIAL INFORMATION

 

 

 

 

 

 

 

Page

 

 

 

 

ITEM 1.

Financial Statements (Unaudited)

 

 

 

 

 

 

 

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

 

 

 

 

 

 

 

Condensed Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013

 

1

 

 

 

 

 

Condensed Consolidated Statements of Income for the three and six months ended June 30, 2014 and 2013

 

2

 

 

 

 

 

Condensed Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2014 and 2013

 

3

 

 

 

 

 

Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013

 

4

 

 

 

 

 

Notes to Condensed Consolidated Financial Statements

 

5

 

 

 

 

ITEM 2.

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

 

17

 

 

 

 

ITEM 3.

Quantitative and Qualitative Disclosures about Market Risk

 

33

 

 

 

 

ITEM 4.

Controls and Procedures

 

34

 

 

 

 

 

Forward-Looking Statements

 

35

 

 

 

 

PART II

 

OTHER INFORMATION

 

 

 

 

ITEM 1.

Legal Proceedings

 

37

 

 

 

 

ITEM 1A.

Risk Factors

 

37

 

 

 

 

ITEM 2.

Unregistered Sales of Equity Securities and Use of Proceeds

 

37

 

 

 

 

ITEM 3.

Defaults Upon Senior Securities

 

37

 

 

 

 

ITEM 4.

Mine Safety Disclosures

 

37

 

 

 

 

ITEM 5.

Other Information

 

37

 

 

 

 

ITEM 6.

Exhibits

 

38

 

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Table of Contents

 

PART I

 

FINANCIAL INFORMATION

 

ITEM 1.  FINANCIAL STATEMENTS

 

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)

 

 

 

June 30,

 

December 31,

 

ASSETS

 

2014

 

2013

 

 

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

 

  $

19,435

 

  $

93,654

 

Trade receivables

 

174,753

 

153,662

 

Other receivables

 

1,104

 

776

 

Due from affiliates

 

3,134

 

1,964

 

Inventories

 

54,491

 

44,214

 

Advance royalties

 

11,072

 

11,454

 

Prepaid expenses and other assets

 

5,544

 

16,186

 

Total current assets

 

269,533

 

321,910

 

 

 

 

 

 

 

PROPERTY, PLANT AND EQUIPMENT:

 

 

 

 

 

Property, plant and equipment, at cost

 

2,703,121

 

2,645,872

 

Less accumulated depreciation, depletion and amortization

 

(1,067,836)

 

(1,031,493)

 

Total property, plant and equipment, net

 

1,635,285

 

1,614,379

 

 

 

 

 

 

 

OTHER ASSETS:

 

 

 

 

 

Advance royalties

 

19,021

 

18,813

 

Due from affiliate

 

11,361

 

11,560

 

Equity investments in affiliates

 

176,506

 

130,410

 

Other long-term assets

 

24,287

 

24,826

 

Total other assets

 

231,175

 

185,609

 

TOTAL ASSETS

 

  $

2,135,993

 

  $

2,121,898

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Accounts payable

 

  $

89,871

 

  $

79,371

 

Due to affiliates

 

161

 

290

 

Accrued taxes other than income taxes

 

23,318

 

19,061

 

Accrued payroll and related expenses

 

43,307

 

47,105

 

Accrued interest

 

906

 

996

 

Workers’ compensation and pneumoconiosis benefits

 

9,287

 

9,065

 

Current capital lease obligations

 

1,306

 

1,288

 

Other current liabilities

 

13,622

 

18,625

 

Current maturities, long-term debt

 

248,000

 

36,750

 

Total current liabilities

 

429,778

 

212,551

 

 

 

 

 

 

 

LONG-TERM LIABILITIES:

 

 

 

 

 

Long-term debt, excluding current maturities

 

533,750

 

831,250

 

Pneumoconiosis benefits

 

50,924

 

48,455

 

Accrued pension benefit

 

16,933

 

18,182

 

Workers’ compensation

 

53,334

 

54,949

 

Asset retirement obligations

 

76,404

 

80,807

 

Long-term capital lease obligations

 

16,383

 

17,135

 

Other liabilities

 

6,326

 

7,332

 

Total long-term liabilities

 

754,054

 

1,058,110

 

Total liabilities

 

1,183,832

 

1,270,661

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES

 

 

 

 

 

 

 

 

 

 

 

PARTNERS CAPITAL:

 

 

 

 

 

Limited Partners - Common Unitholders 74,060,634 and 73,926,108 units outstanding, respectively

 

1,225,554

 

1,128,519

 

General Partners’ deficit

 

(263,535)

 

(267,563)

 

Accumulated other comprehensive loss

 

(9,858)

 

(9,719)

 

Total Partners’ Capital

 

952,161

 

851,237

 

TOTAL LIABILITIES AND PARTNERS’ CAPITAL

 

  $

2,135,993

 

  $

2,121,898

 

 

See notes to condensed consolidated financial statements.

 

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except unit and per unit data)

(Unaudited)

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

SALES AND OPERATING REVENUES:

 

 

 

 

 

 

 

 

 

Coal sales

 

$

575,191

 

$

541,574

 

$

1,100,736

 

$

1,076,083

 

Transportation revenues

 

5,810

 

4,971

 

11,815

 

11,905

 

Other sales and operating revenues

 

17,561

 

7,026

 

28,049

 

13,638

 

Total revenues

 

598,562

 

553,571

 

1,140,600

 

1,101,626

 

 

 

 

 

 

 

 

 

 

 

EXPENSES:

 

 

 

 

 

 

 

 

 

Operating expenses (excluding depreciation, depletion and amortization)

 

352,893

 

347,437

 

675,135

 

696,012

 

Transportation expenses

 

5,810

 

4,971

 

11,815

 

11,905

 

Outside coal purchases

 

2

 

790

 

4

 

1,392

 

General and administrative

 

19,771

 

16,597

 

37,206

 

31,843

 

Depreciation, depletion and amortization

 

67,052

 

68,207

 

133,893

 

132,589

 

Total operating expenses

 

445,528

 

438,002

 

858,053

 

873,741

 

 

 

 

 

 

 

 

 

 

 

INCOME FROM OPERATIONS

 

153,034

 

115,569

 

282,547

 

227,885

 

 

 

 

 

 

 

 

 

 

 

Interest expense (net of interest capitalized for the three and six months ended June 30, 2014 and 2013 of $61, $2,873, $833 and $5,404, respectively)

 

(8,748)

 

(6,218)

 

(16,811)

 

(12,836)

 

Interest income

 

417

 

178

 

806

 

312

 

Equity in loss of affiliates, net

 

(7,373)

 

(5,699)

 

(13,614)

 

(9,566)

 

Other income

 

323

 

353

 

629

 

627

 

INCOME BEFORE INCOME TAXES

 

137,653

 

104,183

 

253,557

 

206,422

 

 

 

 

 

 

 

 

 

 

 

INCOME TAX EXPENSE (BENEFIT)

 

-

 

109

 

-

 

(589)

 

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

$

137,653

 

$

104,074

 

$

253,557

 

$

207,011

 

 

 

 

 

 

 

 

 

 

 

GENERAL PARTNERS’ INTEREST IN NET INCOME

 

$

34,781

 

$

30,592

 

$

68,149

 

$

60,362

 

 

 

 

 

 

 

 

 

 

 

LIMITED PARTNERS’ INTEREST IN NET INCOME

 

$

102,872

 

$

73,482

 

$

185,408

 

$

146,649

 

 

 

 

 

 

 

 

 

 

 

BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT (Note 7)

 

$

1.37

 

$

0.98

 

$

2.47

 

$

1.96

 

 

 

 

 

 

 

 

 

 

 

DISTRIBUTIONS PAID PER LIMITED PARTNER UNIT

 

$

0.61125

 

$

0.565

 

$

1.21

 

$

1.11875

 

 

 

 

 

 

 

 

 

 

 

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING – BASIC AND DILUTED

 

74,060,634

 

73,926,108

 

74,027,932

 

73,882,298

 

 

See notes to condensed consolidated financial statements.

 

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)

 

 

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

 $

137,653

 

 $

104,074

 

 $

253,557

 

 $

207,011

 

 

 

 

 

 

 

 

 

 

 

OTHER COMPREHENSIVE (LOSS)/INCOME:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Defined benefit pension plan:

 

 

 

 

 

 

 

 

 

Amortization of actuarial loss (1)

 

162

 

559

 

387

 

1,118

 

Total defined benefit pension plan adjustments

 

162

 

559

 

387

 

1,118

 

 

 

 

 

 

 

 

 

 

 

Pneumoconiosis benefits:

 

 

 

 

 

 

 

 

 

Amortization of actuarial (gain)/loss (1)

 

(263)

 

167

 

(526)

 

335

 

Total pneumoconiosis benefits adjustments

 

(263)

 

167

 

(526)

 

335

 

 

 

 

 

 

 

 

 

 

 

OTHER COMPREHENSIVE (LOSS)/INCOME

 

(101)

 

726

 

(139)

 

1,453

 

 

 

 

 

 

 

 

 

 

 

TOTAL COMPREHENSIVE INCOME

 

 $

137,552

 

 $

104,800

 

 $

253,418

 

 $

208,464

 

 

(1)          Amortization of actuarial (gain)/loss is included in the computation of net periodic benefit cost (see Notes 8 and 10 for additional details).

 

See notes to condensed consolidated financial statements.

 

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

 

 

 

 

Six Months Ended
June 30,

 

 

 

2014

 

2013

 

 

 

 

 

 

 

CASH FLOWS PROVIDED BY OPERATING ACTIVITIES

 

  $

379,389

 

  $

373,823

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

Property, plant and equipment:

 

 

 

 

 

Capital expenditures

 

(154,578)

 

(163,030)

 

Changes in accounts payable and accrued liabilities

 

2,608

 

(4,055)

 

Proceeds from sale of property, plant and equipment

 

19

 

9

 

Proceeds from insurance settlement for property, plant and equipment

 

4,512

 

-

 

Purchases of equity investments in affiliate

 

(60,000)

 

(47,500)

 

Payments to affiliate for acquisition and development of coal reserves

 

(1,401)

 

(18,860)

 

Advances/loans to affiliate

 

-

 

(2,531)

 

Net cash used in investing activities

 

(208,840)

 

(235,967)

 

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

Payments under term loan

 

(6,250)

 

-

 

Borrowings under revolving credit facilities

 

142,800

 

77,000

 

Payments under revolving credit facilities

 

(222,800)

 

(90,000)

 

Payments on capital lease obligations

 

(734)

 

(584)

 

Net settlement of employee withholding taxes on vesting of Long-Term Incentive Plan

 

(2,991)

 

(3,015)

 

Cash contributions by General Partners

 

111

 

114

 

Distributions paid to Partners

 

(154,904)

 

(140,860)

 

Net cash used in financing activities

 

(244,768)

 

(157,345)

 

 

 

 

 

 

 

NET CHANGE IN CASH AND CASH EQUIVALENTS

 

(74,219)

 

(19,489)

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD

 

93,654

 

28,283

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS AT END OF PERIOD

 

  $

19,435

 

  $

8,794

 

 

 

 

 

 

 

SUPPLEMENTAL CASH FLOW INFORMATION:

 

 

 

 

 

Cash paid for interest

 

  $

17,184

 

  $

17,660

 

 

 

 

 

 

 

NON-CASH INVESTING AND FINANCING ACTIVITY:

 

 

 

 

 

Accounts payable for purchase of property, plant and equipment

 

  $

20,532

 

  $

16,917

 

Market value of common units issued under Long-Term Incentive and Directors Deferred Compensation Plans before minimum statutory tax withholding requirements

 

  $

8,417

 

  $

8,583

 

Disposition of property, plant and equipment:

 

 

 

 

 

Net change in assets

 

  $

846

 

  $

-

 

Book value of liabilities transferred

 

(5,246)

 

-

 

Gain recognized

 

  $

(4,400)

 

  $

-

 

 

See notes to condensed consolidated financial statements.

 

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1.         ORGANIZATION AND PRESENTATION

 

Significant Relationships Referenced in Notes to Condensed Consolidated Financial Statements

 

·

References to “we,” “us,” “our” or “ARLP Partnership” mean the business and operations of Alliance Resource Partners, L.P., the parent company, as well as its consolidated subsidiaries.

·

References to “ARLP” mean Alliance Resource Partners, L.P., individually as the parent company, and not on a consolidated basis.

·

References to “MGP” mean Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P, also referred to as our managing general partner.

·

References to “SGP” mean Alliance Resource GP, LLC, the special general partner of Alliance Resource Partners, L.P., also referred to as our special general partner.

·

References to “Intermediate Partnership” mean Alliance Resource Operating Partners, L.P., the intermediate partnership of Alliance Resource Partners, L.P., also referred to as our intermediate partnership.

·

References to “Alliance Coal” mean Alliance Coal, LLC, the holding company for the operations of Alliance Resource Operating Partners, L.P., also referred to as our operating subsidiary.

·

References to “AHGP” mean Alliance Holdings GP, L.P., individually as the parent company, and not on a consolidated basis.

·

References to “AGP” mean Alliance GP, LLC, the general partner of Alliance Holdings GP, L.P.

 

Organization

 

ARLP is a Delaware limited partnership listed on the NASDAQ Global Select Market under the ticker symbol “ARLP.”  ARLP was formed in May 1999 to acquire, upon completion of ARLP’s initial public offering on August 19, 1999, certain coal production and marketing assets of Alliance Resource Holdings, Inc., a Delaware corporation (“ARH”), consisting of substantially all of ARH’s operating subsidiaries, but excluding ARH.  ARH is owned by Joseph W. Craft III, the President and Chief Executive Officer and a Director of our managing general partner, and Kathleen S. Craft.  SGP, a Delaware limited liability company, is owned by ARH and holds a 0.01% general partner interest in each of ARLP and the Intermediate Partnership.

 

We are managed by our managing general partner, MGP, a Delaware limited liability company, which holds a 0.99% and a 1.0001% managing general partner interest in ARLP and the Intermediate Partnership, respectively, and a 0.001% managing member interest in Alliance Coal.  AHGP is a Delaware limited partnership that was formed to become the owner and controlling member of MGP.  AHGP completed its initial public offering on May 15, 2006.  AHGP owns directly and indirectly 100% of the members’ interest of MGP, the incentive distribution rights (“IDR”) in ARLP and 31,088,338 common units of ARLP.

 

Basis of Presentation

 

The accompanying condensed consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of June 30, 2014 and December 31, 2013, and the results of our operations and comprehensive income for the three and six months ended June 30, 2014 and 2013 and the cash flows for the six months ended June 30, 2014 and 2013.  All of our intercompany transactions and accounts have been eliminated.

 

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These condensed consolidated financial statements and notes are unaudited. However, in the opinion of management, these financial statements reflect all adjustments (which include only normal recurring adjustments) necessary for a fair presentation of the results for the periods presented.  Results for interim periods are not necessarily indicative of results for a full year.

 

These condensed consolidated financial statements and notes are prepared pursuant to the rules and regulations of the Securities and Exchange Commission for interim reporting and should be read in conjunction with the consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2013.

 

On June 16, 2014, we completed a two-for-one split of our common units, whereby holders of record as of May 30, 2014 received a one unit distribution on each unit outstanding on that date.  The unit split resulted in the issuance of 37,030,317 common units.  All references to the number of units and per unit net income and distribution amounts included in this report have been adjusted to give effect for this unit split for all periods presented.  Also, ARLP’s partnership agreement was amended effective June 16, 2014, to reduce the target thresholds for the incentive distribution rights per unit by half.

 

Use of Estimates

 

The preparation of the ARLP Partnership’s condensed consolidated financial statements in conformity with generally accepted accounting principles of the United States (“U.S.”) requires management to make estimates and assumptions that affect the reported amounts and disclosures in our condensed consolidated financial statements.  Actual results could differ from those estimates.

 

2.         NEW ACCOUNTING STANDARDS

 

New Accounting Standards Issued and Not Yet Adopted

 

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”).  ASU 2014-08 changes the requirements for reporting discontinued operations in Accounting Standards Codification 205, Presentation of Financial Statements, by updating the criteria for determining which disposals can be presented as discontinued operations and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of discontinued operations.  ASU 2014-08 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2014.  We do not anticipate the adoption of ASU 2014-08 on January 1, 2015 will have a material impact on our consolidated financial statements.

 

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”).  ASU 2014-09 is a new revenue recognition standard that provides a five-step analysis of transactions to determine when and how revenue is recognized.  The core principle of the new standard is an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016 and shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption.  Early adoption is not permitted.  We are currently evaluating the effect of adopting ASU 2014-09 on January 1, 2017.

 

3.         CONTINGENCIES

 

Various lawsuits, claims and regulatory proceedings incidental to our business are pending against the ARLP Partnership.  We record an accrual for a potential loss related to these matters when, in management’s opinion, such loss is probable and reasonably estimable.  Based on known facts and circumstances, we believe the ultimate outcome of these outstanding lawsuits, claims and regulatory

 

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proceedings will not have a material adverse effect on our financial condition, results of operations or liquidity.  However, if the results of these matters were different from management’s current opinion and in amounts greater than our accruals, then they could have a material adverse effect.

 

4.         FAIR VALUE MEASUREMENTS

 

We apply the provisions of FASB ASC 820, Fair Value Measurement, which, among other things, defines fair value, requires disclosures about assets and liabilities carried at fair value and establishes a hierarchal disclosure framework based upon the quality of inputs used to measure fair value.

 

Valuation techniques are based upon observable and unobservable inputs.  Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our own market assumptions.  These two types of inputs create the following fair value hierarchy:

 

·                  Level 1 – Quoted prices for identical instruments in active markets.

·               Level 2 – Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model derived valuations whose inputs are observable or whose significant value drivers are observable.

·                  Level 3 – Instruments whose significant value drivers are unobservable.

 

The carrying amounts for cash equivalents, accounts receivable, accounts payable, due from affiliates and due to affiliates approximate fair value because of the short maturity of those instruments.  At June 30, 2014 and December 31, 2013, the estimated fair value of our long-term debt, including current maturities, was approximately $793.8 million and $884.8 million, respectively, based on interest rates that we believe are currently available to us for issuance of debt with similar terms and remaining maturities (Note 5). The fair value of debt, which is based upon interest rates for similar instruments in active markets, is classified as a Level 2 measurement under the fair value hierarchy.

 

5.         LONG-TERM DEBT

 

Long-term debt consists of the following (in thousands):

 

 

 

June 30,
2014

 

December 31,
2013

 

 

 

 

 

 

 

Revolving Credit facility

 

  $

170,000

 

  $

250,000

 

Senior notes

 

18,000

 

18,000

 

Series A senior notes

 

205,000

 

205,000

 

Series B senior notes

 

145,000

 

145,000

 

Term loan

 

243,750

 

250,000

 

 

 

781,750

 

868,000

 

Less current maturities

 

(248,000)

 

(36,750)

 

Total long-term debt

 

  $

533,750

 

  $

831,250

 

 

Our Intermediate Partnership has $18.0 million in senior notes (“Senior Notes”), $205.0 million in Series A and $145.0 million in Series B senior notes (collectively, the “2008 Senior Notes”), a $700.0 million revolving credit facility (“Revolving Credit Facility”) and a $243.8 million term loan (“Term Loan”) (collectively, with the Senior Notes, the 2008 Senior Notes and the Revolving Credit Facility, the “ARLP Debt Arrangements”), which are guaranteed by all of the material direct and indirect subsidiaries of our Intermediate Partnership.  At June 30, 2014, current maturities include Senior Notes, due in August 2014, Series A Senior notes, due in June 2015, and a portion of the Term Loan.  The ARLP Debt Arrangements contain various covenants affecting our Intermediate Partnership and its subsidiaries restricting, among other things, the amount of distributions by our Intermediate Partnership, incurrence of

 

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additional indebtedness and liens, sale of assets, investments, mergers and consolidations and transactions with affiliates, in each case subject to various exceptions.  The ARLP Debt Arrangements also require the Intermediate Partnership to remain in control of a certain amount of mineable coal reserves relative to its annual production.  In addition, the ARLP Debt Arrangements require our Intermediate Partnership to maintain (a) debt to cash flow ratio of not more than 3.0 to 1.0 and (b) cash flow to interest expense ratio of not less than 3.0 to 1.0, in each case, during the four most recently ended fiscal quarters.  The debt to cash flow ratio and cash flow to interest expense ratio were 1.05 to 1.0 and 21.5 to 1.0, respectively, for the trailing twelve months ended June 30, 2014.  We were in compliance with the covenants of the ARLP Debt Arrangements as of June 30, 2014.

 

At June 30, 2014, we had borrowings of $170.0 million and $5.4 million of letters of credit outstanding with $524.6 million available for borrowing under the Revolving Credit Facility.  We utilize the Revolving Credit Facility, as appropriate, for working capital requirements, capital expenditures and investments in affiliates, scheduled debt payments and distribution payments.  We incur an annual commitment fee of 0.25% on the undrawn portion of the Revolving Credit Facility.

 

6.                                    WHITE OAK TRANSACTIONS

 

On September 22, 2011 (the “Transaction Date”), we entered into a series of transactions with White Oak Resources LLC (“White Oak”) and related entities to support development of a longwall mining operation currently under construction.  The transactions feature several components, including an equity investment in White Oak (represented by “Series A Units” containing certain distribution and liquidation preferences), the acquisition and lease-back of certain coal reserves and surface rights and a construction loan.  Our initial investment funding to White Oak at the Transaction Date, consummated utilizing existing cash on hand, was $69.5 million and we have funded White Oak $278.1 million between the Transaction Date and June 30, 2014.  We expect to fund a total of approximately $395.5 million to $425.5 million from the Transaction Date through December 31, 2015, which includes the funding made to White Oak through June 30, 2014 discussed above.  We expect to fund these additional commitments utilizing existing cash balances, future cash flows from operations, borrowings under credit facilities and cash provided from the issuance of debt or equity.  On the Transaction Date, we also entered into a coal handling and services agreement, pursuant to which we constructed and are operating a preparation plant and other surface facilities.  The following information discusses each component of these transactions in further detail.

 

Hamilton County, Illinois Reserve Acquisition

 

On the Transaction Date, Alliance WOR Properties, LLC (“WOR Properties”) acquired from White Oak the rights to approximately 204.9 million tons of proven and probable high-sulfur coal reserves, of which 105.2 million tons are currently being developed for future mining by White Oak, and certain surface properties and rights in Hamilton County, Illinois (the “Reserve Acquisition”), which is adjacent to White County, Illinois, where our White County Coal, LLC’s Pattiki mine is located.  The asset purchase price of $33.8 million cash paid at closing was allocated to owned and leased coal rights.  Between the Transaction Date and December 31, 2012, WOR Properties provided $51.6 million to White Oak for development of the acquired coal reserves, fulfilling its initial commitment for further development funding.  During the twelve months ended December 31, 2013, WOR Properties acquired from White Oak, for $25.3 million cash paid at various closings, an additional 90.1 million tons of reserves.  During the six months ended June 30, 2014, WOR Properties acquired from White Oak, for $1.4 million cash paid at closing, an additional 5.1 million tons of reserves.  Of the additional tons acquired in 2013 and the six months ended June 30, 2014, 48.5 million tons are currently being developed for future mining by White Oak.  At June 30, 2014, WOR Properties had provided $112.1 million to acquire a total of 300.1 million tons of coal reserves and fund the development of the acquired reserves.  WOR Properties has a remaining commitment of $27.9 million for additional coal reserve acquisitions and development funding.

 

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Equity Investment – Series A Units

 

Concurrent with the Reserve Acquisition, our subsidiary, Alliance WOR Processing, LLC (“WOR Processing”), made an initial equity investment of $35.7 million in White Oak to purchase Series A Units representing ownership in White Oak.  WOR Processing purchased $129.3 million of additional Series A Units between the Transaction Date and December 31, 2013, and fulfilled WOR Processing’s minimum equity investment commitment of $150.0 million.  During the six months ended June 30, 2014, WOR Processing purchased $60.0 million of additional Series A Units, bringing our total investment in Series A Units to $225.0 million at June 30, 2014.

 

WOR Processing’s ownership and member’s voting interest in White Oak at June 30, 2014 were 35.0% based upon currently outstanding voting units.  The remainder of the equity ownership in White Oak, represented by Series A and B Units, is held by other investors and members of White Oak management.

 

We continually review all rights provided to WOR Processing and us by various agreements with White Oak and continue to conclude all such rights are protective or participating in nature and do not provide WOR Processing or us the ability to unilaterally direct any of the primary activities of White Oak that most significantly impact its economic performance.  As such, we recognize WOR Processing’s interest in White Oak as an equity investment in affiliate in our consolidated balance sheets.  As of June 30, 2014, WOR Processing had invested $225.0 million in Series A Units of White Oak equity, which represents our current maximum exposure to loss as a result of our equity investment in White Oak exclusive of capitalized interest.  White Oak has made no distributions to us.

 

We record WOR Processing’s equity in earnings or losses of affiliates under the hypothetical liquidation at book value method of accounting due to the preferences to which WOR Processing is entitled on distributions.  For the three and six months ended June 30, 2014 and 2013, we were allocated losses of $7.5 million, $5.9 million, $13.8 million and $10.1 million, respectively.

 

Services Agreement

 

Simultaneous with the closing of the Reserve Acquisition, WOR Processing entered into a Coal Handling and Preparation Agreement with White Oak pursuant to which WOR Processing committed to construct and operate a coal preparation plant and related facilities and a rail loop and loadout facility to service the White Oak longwall Mine No. 1.  For the three and six months ended June 30, 2014, WOR Processing earned throughput fees of $3.8 million and $7.4 million, respectively, from White Oak for processing and loading coal through the facilities.  Throughput fees earned from White Oak are included in the other sales and operating revenues line item within our condensed consolidated statements of income.

 

In addition, the Intermediate Partnership agreed to loan $10.5 million to White Oak for the construction of various assets on the surface property, including but not limited to, a bathhouse, office and warehouse (“Construction Loan”).  The Construction Loan has a term of 20 years, with repayment scheduled to begin in 2015.  White Oak had borrowed the entire amount available under the Construction Loan as of June 30, 2014.

 

7.         NET INCOME PER LIMITED PARTNER UNIT

 

We apply the provisions of FASB ASC 260, Earnings Per Share, which requires the two-class method in calculating basic and diluted earnings per unit (“EPU”).  Net income is allocated to the general partners and limited partners in accordance with their respective partnership percentages, after giving effect to any special income or expense allocations, including incentive distributions to our managing general partner, the holder of the IDR pursuant to our partnership agreement, which are declared and paid following the end of each quarter. Under the quarterly IDR provisions of our partnership agreement, our

 

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managing general partner is entitled to receive 15% of the amount we distribute in excess of $0.1375 per unit, 25% of the amount we distribute in excess of $0.15625 per unit, and 50% of the amount we distribute in excess of $0.1875 per unit.  Our partnership agreement contractually limits our distributions to available cash; therefore, undistributed earnings of the ARLP Partnership are not allocated to the IDR holder.  In addition, outstanding awards under our Long-Term Incentive Plan (“LTIP”) and phantom units in notional accounts under our Supplemental Executive Retirement Plan (“SERP”) and the MGP Amended and Restated Deferred Compensation Plan for Directors (“Deferred Compensation Plan”) include rights to nonforfeitable distributions or distribution equivalents and are therefore considered participating securities.  As such, we allocate undistributed and distributed earnings to these outstanding awards in our calculation of EPU.  The following is a reconciliation of net income used for calculating basic earnings per unit and the weighted average units used in computing EPU for the three and six months ended June 30, 2014 and 2013 (in thousands, except per unit data):

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

137,653

 

$

104,074

 

$

253,557

 

$

207,011

 

Adjustments:

 

 

 

 

 

 

 

 

 

Managing general partner’s priority distributions

 

(32,682)

 

(29,092)

 

(64,366)

 

(57,369)

 

General partners’ 2% equity ownership

 

(2,099)

 

(1,500)

 

(3,783)

 

(2,993)

 

 

 

 

 

 

 

 

 

 

 

Limited partners’ interest in net income

 

102,872

 

73,482

 

185,408

 

146,649

 

 

 

 

 

 

 

 

 

 

 

Less:

 

 

 

 

 

 

 

 

 

Distributions to participating securities

 

(729)

 

(583)

 

(1,437)

 

(1,152)

 

Undistributed earnings attributable to participating securities

 

(886)

 

(415)

 

(1,440)

 

(847)

 

 

 

 

 

 

 

 

 

 

 

Net income available to limited partners

 

$

101,257

 

$

72,484

 

$

182,531

 

$

144,650

 

 

 

 

 

 

 

 

 

 

 

Weighted average limited partner units outstanding – basic and diluted

 

74,061

 

73,926

 

74,028

 

73,882

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted net income per limited partner unit (1)

 

$

1.37

 

$

0.98

 

$

2.47

 

$

1.96

 

 

(1)          Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive.  For the three and six months ended June 30, 2014 and 2013, LTIP, SERP and Deferred Compensation Plan units of 755,210, 690,304, 748,446 and 634,334 respectively, were considered anti-dilutive under the treasury stock method.

 

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8.                                    WORKERS’ COMPENSATION AND PNEUMOCONIOSIS

 

The changes in the workers’ compensation liability (including current and long-term liability balances) for each of the periods presented were as follows (in thousands):

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

 $

62,989

 

 

 $

78,755

 

 

 $

62,909

 

 

 $

77,046

 

Accruals increase

 

5,281

 

 

3,982

 

 

7,464

 

 

7,947

 

Payments

 

(2,778

)

 

(2,727

)

 

(5,527

)

 

(5,603

)

Interest accretion

 

647

 

 

620

 

 

1,293

 

 

1,240

 

Valuation gain (1)

 

(4,624

)

 

-

 

 

(4,624

)

 

-

 

Ending balance

 

 $

61,515

 

 

 $

80,630

 

 

 $

61,515

 

 

 $

80,630

 

 

(1)      Our liability for the estimated present value of current workers’ compensation benefits is based on our actuarial estimates. Our actuarial calculations are based on a blend of actuarial projection methods and numerous assumptions including claim development patterns, mortality, medical costs and interest rates. We conducted a mid-year review of our actuarial assumptions which resulted in a valuation gain in 2014 primarily attributable to favorable changes in claims development, offset partially by a decrease in the discount rate used to calculate the estimated present value of future obligations from 4.11% at December 31, 2013 to 3.67% at June 30, 2014.

 

Certain of our mine operating entities are liable under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay pneumoconiosis, or black lung, benefits to eligible employees and former employees and their dependents. Components of the net periodic benefit cost for each of the periods presented are as follows (in thousands):

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

 $

857

 

 

 $

951

 

 

 $

1,714

 

 

 $

1,905

 

Interest cost

 

565

 

 

564

 

 

1,131

 

 

1,127

 

Amortization of net (gain)/loss (1)

 

(263

)

 

167

 

 

(526

)

 

335

 

Net periodic benefit cost

 

 $

1,159

 

 

 $

1,682

 

 

 $

2,319

 

 

 $

3,367

 

 

(1)      Amortization of net (gain)/loss is included in the operating expenses line item within our condensed consolidated statements of income.

 

9.                                    COMPENSATION PLANS

 

Long-Term Incentive Plan

 

We have the LTIP for certain employees and officers of our managing general partner and its affiliates who perform services for us. The LTIP awards are grants of non-vested “phantom” or notional units, which upon satisfaction of vesting requirements, entitle the LTIP participant to receive ARLP common units. Annual grant levels and vesting provisions for designated participants are recommended by our President and Chief Executive Officer, subject to review and approval of the compensation committee of the MGP board of directors (the “Compensation Committee”). On January 22, 2014, the Compensation Committee determined that the vesting requirements for the 2011 grants of 202,742

 

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restricted units (which is net of 14,090 forfeitures) had been satisfied as of January 1, 2014. As a result of this vesting, on February 14, 2014, we issued 128,610 unrestricted common units to the LTIP participants. The remaining units were settled in cash to satisfy the individual statutory minimum tax obligations of the LTIP participants. On January 22, 2014, the Compensation Committee authorized additional grants of up to 370,410 restricted units, of which 350,890 were granted during the six months ended June 30, 2014 and will vest on January 1, 2017, subject to satisfaction of certain financial tests. The fair value of these 2014 grants is equal to the intrinsic value at the date of grant, which was $40.58 per unit. LTIP expense was $2.5 million and $1.9 million for the three months ended June 30, 2014 and 2013, respectively, and $4.6 million and $3.6 million for the six months ended June 30, 2014 and 2013, respectively. After consideration of the January 1, 2014 vesting and subsequent issuance of 128,610 common units, approximately 3.9 million units remain available under the LTIP for issuance in the future, assuming all grants issued in 2012, 2013 and 2014 currently outstanding are settled with common units, without reduction for tax withholding, and no future forfeitures occur.

 

As of June 30, 2014, there was $17.4 million in total unrecognized compensation expense related to the non-vested LTIP grants that are expected to vest. That expense is expected to be recognized over a weighted-average period of 1.7 years. As of June 30, 2014, the intrinsic value of the non-vested LTIP grants was $39.3 million. As of June 30, 2014, the total obligation associated with the LTIP was $12.7 million and is included in the partners’ capital-limited partners line item in our condensed consolidated balance sheets.

 

As provided under the distribution equivalent rights provisions of the LTIP, all non-vested grants include contingent rights to receive quarterly cash distributions in an amount equal to the cash distributions we make to unitholders during the vesting period.

 

SERP and Directors Deferred Compensation Plan

 

We utilize the SERP to provide deferred compensation benefits for certain officers and key employees. All allocations made to participants under the SERP are made in the form of “phantom” ARLP units. The SERP is administered by the Compensation Committee.

 

Our directors participate in the Deferred Compensation Plan. Pursuant to the Deferred Compensation Plan, for amounts deferred either automatically or at the election of the director, a notional account is established and credited with notional common units of ARLP, described in the Deferred Compensation Plan as “phantom” units.

 

For both the SERP and Deferred Compensation Plan, when quarterly cash distributions are made with respect to ARLP common units, an amount equal to such quarterly distribution is credited to each participant’s notional account as additional phantom units. All grants of phantom units under the SERP and Deferred Compensation Plan vest immediately.

 

For the six months ended June 30, 2014 and 2013, SERP and Deferred Compensation Plan participant notional account balances were credited with a total of 10,806 and 14,848 phantom units, respectively, and the fair value of these phantom units was $42.93 per unit and $32.97 per unit, respectively, on a weighted-average basis. Total SERP and Deferred Compensation Plan expense was approximately $0.3 million for each of the three months ended June 30, 2014 and 2013, and $0.6 million for each of the six months ended June 30, 2014 and 2013.

 

As of June 30, 2014, there were 352,210 total phantom units outstanding under the SERP and Deferred Compensation Plan and the total intrinsic value of the SERP and Deferred Compensation Plan phantom units was $16.4 million. As of June 30, 2014, the total obligation associated with the SERP and Deferred Compensation Plan was $11.8 million and is included in the partners’ capital-limited partners line item in our condensed consolidated balance sheets. On February 14, 2014, we issued 5,916 ARLP common units to directors under the Deferred Compensation Plan.

 

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10.                            COMPONENTS OF PENSION PLAN NET PERIODIC BENEFIT COSTS

 

Eligible employees at certain of our mining operations participate in a defined benefit plan (the “Pension Plan”) that we sponsor. The benefit formula for the Pension Plan is a fixed dollar unit based on years of service.

 

Components of the net periodic benefit cost for each of the periods presented are as follows (in thousands):

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

 $

544

 

 

 $

674

 

 

 $

1,087

 

 

 $

1,434

 

Interest cost

 

1,018

 

 

929

 

 

2,037

 

 

1,781

 

Expected return on plan assets

 

(1,337

)

 

(931

)

 

(2,738

)

 

(2,164

)

Amortization of net loss (1)

 

162

 

 

559

 

 

387

 

 

1,118

 

Net periodic benefit cost

 

 $

387

 

 

 $

1,231

 

 

 $

773

 

 

 $

2,169

 

 

(1)          Amortization of net loss is included in the operating expenses line item within our condensed consolidated statements of income.

 

We previously disclosed in our financial statements for the year ended December 31, 2013 that we expected to contribute $3.6 million to the Pension Plan in 2014. During the six months ended June 30, 2014, we made contribution payments of $0.8 million to the Pension Plan for the 2013 plan year and $0.8 million for the 2014 plan year. On July 15, 2014, we made a contribution payment of $0.8 million for the 2014 plan year. We expect to make additional contributions of $0.3 million for the 2013 plan year and $0.9 million for the 2014 plan year for the remainder of 2014 and, therefore, will contribute approximately $3.6 million to the Pension Plan in 2014.

 

11.                            SEGMENT INFORMATION

 

We operate in the eastern U.S. as a producer and marketer of coal to major utilities and industrial users. We aggregate multiple operating segments into four reportable segments: the Illinois Basin, Appalachia, White Oak and Other and Corporate. The first two reportable segments correspond to major coal producing regions in the eastern U.S. Similar economic characteristics for our operating segments within each of these two reportable segments generally include coal quality, geology, coal marketing opportunities, mining and transportation methods and regulatory issues. The White Oak reportable segment includes our activities associated with the White Oak longwall Mine No. 1 development project more fully described below.

 

The Illinois Basin reportable segment is comprised of multiple operating segments, including Webster County Coal, LLC’s Dotiki mining complex, Gibson County Coal, LLC’s mining complex, which includes the Gibson North mine and Gibson South mine, Hopkins County Coal, LLC’s Elk Creek mining complex, White County Coal, LLC’s Pattiki mining complex, Warrior Coal, LLC’s mining complex, Sebree Mining, LLC’s mining complex, which includes the Onton mine, and River View Coal, LLC’s mining complex. The development of the Gibson South mine continues and includes incidental production which began in April 2014.

 

The Appalachian reportable segment is comprised of multiple operating segments, including the Mettiki mining complex, the Tunnel Ridge, LLC mining complex, the MC Mining, LLC mining complex and the Penn Ridge Coal, LLC (“Penn Ridge”) property. The Mettiki mining complex includes Mettiki Coal (WV), LLC’s Mountain View mine, Mettiki Coal, LLC’s preparation plant and a small third-party mining operation which has been idled since July 2013. We are in the process of permitting the Penn Ridge property for future mine development.

 

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The White Oak reportable segment is comprised of two operating segments, WOR Processing and WOR Properties. WOR Processing includes both the surface operations at White Oak and the equity investment in White Oak. WOR Properties owns coal reserves acquired from White Oak under lease-back arrangements (Note 6).

 

The Other and Corporate segment includes marketing and administrative expenses, Alliance Service, Inc. (“ASI”) and its subsidiary, Matrix Design Group, LLC (“Matrix Design”), Alliance Design Group, LLC (“Alliance Design”) (collectively, Matrix Design and Alliance Design are referred to as the “Matrix Group”), ASI’s ownership of aircraft, the Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) dock activities, coal brokerage activity, our equity investment in Mid-America Carbonates, LLC, certain activities of Alliance Resource Properties and the Pontiki Coal, LLC mining complex (“Pontiki”), which ceased operations in November 2013 and sold most of its assets in May 2014.

 

As a result of the cessation of operations at Pontiki in November 2013, we evaluated the ongoing management of our mining operations and coal sales efforts to ensure that resources were appropriately allocated to maximize our overall results. Based on this evaluation, we have realigned the management of our operating and marketing teams and changed our reportable segment presentation to reflect this realignment. Due to the change in our reportable segment presentation in 2014, certain reclassifications of 2013 segment information have been made to conform to the 2014 presentation. These reclassifications include changes to the Appalachian segment and Other and Corporate segment.

 

Reportable segment results as of and for the three and six months ended June 30, 2014 and 2013 are presented below.

 

 

 

Illinois
Basin

 

Appalachia

 

White Oak

 

Other and
Corporate

 

Elimination
(1)

 

Consolidated

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reportable segment results for the three months ended June 30, 2014 were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenues (2)

 

 $

424,523

 

 

 $

164,096

 

 

 $

4,170

 

 

 $

8,188

 

 

 $

(2,415

)

 

 $

598,562

 

Segment Adjusted EBITDA Expense (3)

 

255,942

 

 

93,917

 

 

1,625

 

 

3,503

 

 

(2,415

)

 

352,572

 

Segment Adjusted EBITDA (4)(5)

 

165,859

 

 

67,089

 

 

(4,915

)

 

4,774

 

 

-

 

 

232,807

 

Capital expenditures (7)

 

62,166

 

 

18,541

 

 

220

 

 

4,188

 

 

-

 

 

85,115

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reportable segment results for the three months ended June 30, 2013 were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenues (2)

 

 $

400,386

 

 

 $

133,585

 

 

 $

-

 

 

 $

24,522

 

 

 $

(4,922

)

 

 $

553,571

 

Segment Adjusted EBITDA Expense (3)

 

233,703

 

 

96,553

 

 

427

 

 

22,113

 

 

(4,922

)

 

347,874

 

Segment Adjusted EBITDA (4)(5)

 

164,623

 

 

34,120

 

 

(6,295

)

 

2,579

 

 

-

 

 

195,027

 

Capital expenditures (7)

 

52,995

 

 

31,864

 

 

11,917

 

 

2,744

 

 

-

 

 

99,520

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reportable segment results as of and for the six months ended June 30, 2014 were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenues (2)

 

 $

821,025

 

 

 $

301,280

 

 

 $

7,868

 

 

 $

15,930

 

 

 $

(5,503

)

 

 $

1,140,600

 

Segment Adjusted EBITDA Expense (3)

 

485,533

 

 

179,490

 

 

3,016

 

 

11,974

 

 

(5,503

)

 

674,510

 

Segment Adjusted EBITDA (4)(5)

 

329,508

 

 

115,959

 

 

(8,912

)

 

4,106

 

 

-

 

 

440,661

 

Total assets (6)

 

1,102,550

 

 

608,714

 

 

365,380

 

 

60,898

 

 

(1,549

)

 

2,135,993

 

Capital expenditures (7)

 

117,875

 

 

28,669

 

 

2,179

 

 

7,256

 

 

-

 

 

155,979

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reportable segment results as of and for the six months ended June 30, 2013 were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenues (2)

 

 $

805,209

 

 

 $

255,944

 

 

 $

-

 

 

 $

51,029

 

 

 $

(10,556

)

 

 $

1,101,626

 

Segment Adjusted EBITDA Expense (3)

 

467,848

 

 

192,478

 

 

528

 

 

46,479

 

 

(10,556

)

 

696,777

 

Segment Adjusted EBITDA (4)(5)

 

331,844

 

 

57,077

 

 

(10,587

)

 

5,044

 

 

-

 

 

383,378

 

Total assets (6)

 

1,056,953

 

 

603,005

 

 

298,716

 

 

62,325

 

 

(936

)

 

2,020,063

 

Capital expenditures (7)

 

105,026

 

 

44,419

 

 

28,870

 

 

3,575

 

 

-

 

 

181,890

 

 

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Table of Contents

 

(1)

The elimination column represents the elimination of intercompany transactions and is primarily comprised of sales from the Matrix Group to our mining operations and coal sales and purchases between mining operations (2013 only).

 

 

(2)

Revenues included in the Other and Corporate column are primarily attributable to the Matrix Group revenues, Mt. Vernon transloading revenues, administrative service revenues from affiliates, brokerage sales and Pontiki’s coal sales revenue (primarily 2013).

 

 

(3)

Segment Adjusted EBITDA Expense includes operating expenses, outside coal purchases and other income. Transportation expenses are excluded as these expenses are passed through to our customers and consequently we do not realize any gain or loss on transportation revenues. We review Segment Adjusted EBITDA Expense per ton for cost trends.

 

The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to operating expenses (excluding depreciation, depletion and amortization) (in thousands):

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

Segment Adjusted EBITDA Expense

 

 $

352,572

 

 

 $

347,874

 

 

 $

674,510

 

 

 $

696,777

 

Outside coal purchases

 

(2

)

 

(790

)

 

(4

)

 

(1,392

)

Other income

 

323

 

 

353

 

 

629

 

 

627

 

Operating expenses (excluding depreciation, depletion and amortization)

 

 $

352,893

 

 

 $

347,437

 

 

 $

675,135

 

 

 $

696,012

 

 

(4)

Segment Adjusted EBITDA is defined as net income before net interest expense, income taxes, depreciation, depletion and amortization and general and administrative expenses. Management therefore is able to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments. Consolidated Segment Adjusted EBITDA is reconciled to net income as follows (in thousands):

 

 

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Segment Adjusted EBITDA

 

 $

232,807

 

 

 $

195,027

 

 

 $

440,661

 

 

 $

383,378

 

General and administrative

 

(19,771

)

 

(16,597

)

 

(37,206

)

 

(31,843

)

Depreciation, depletion and amortization

 

(67,052

)

 

(68,207

)

 

(133,893

)

 

(132,589

)

Interest expense, net

 

(8,331

)

 

(6,040

)

 

(16,005

)

 

(12,524

)

Income tax (expense) benefit

 

-

 

 

(109

)

 

-

 

 

589

 

Net income

 

 $

137,653

 

 

 $

104,074

 

 

 $

253,557

 

 

 $

207,011

 

 

(5)

Includes equity in income (loss) of affiliates for the three and six months ended June 30, 2014 of $(7.5) million and $(13.8) million, respectively, included in the White Oak segment and $0.1 million, for each period, included in the Other and Corporate segment. Includes equity in income (loss) of affiliates for the three and six months ended June 30, 2013 of $(5.9) million and $(10.1) million, respectively, included in the White Oak segment and $0.2 million and $0.5 million, respectively, included in the Other and Corporate segment.

 

 

(6)

Total assets for the White Oak and Other and Corporate segments include investments in affiliate of $174.9 million and $1.6 million, respectively, at June 30, 2014 and $127.2 million and $1.7 million, respectively, at June 30, 2013.

 

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(7)

Capital expenditures shown above include funding to White Oak of $1.4 million for the six months ended June 30, 2014, no funding for the three months ended June 30, 2014 and $6.8 million and $18.9 million of funding, respectively, for the three and six months ended June 30, 2013, for the acquisition and development of coal reserves from White Oak (Note 6), which is described as “Payments to affiliate for acquisition and development of coal reserves” in our condensed consolidated statements of cash flow.

 

12.                            SUBSEQUENT EVENTS

 

On July 28, 2014, we declared a quarterly distribution for the quarter ended June 30, 2014, of $0.625 per unit, on all common units outstanding, totaling approximately $79.9 million (which includes our managing general partner’s incentive distributions), payable on August 14, 2014 to all unitholders of record as of August 7, 2014. This is the first distribution payable following the recently completed two-for-one unit split.

 

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Table of Contents

 

ITEM 2.                                        MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Significant relationships referenced in this management’s discussion and analysis of financial condition and results of operations include the following:

 

·

References to “we,” “us,” “our” or “ARLP Partnership” mean the business and operations of Alliance Resource Partners, L.P., the parent company, as well as its consolidated subsidiaries.

·

References to “ARLP” mean Alliance Resource Partners, L.P., individually as the parent company, and not on a consolidated basis.

·

References to “MGP” mean Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., also referred to as our managing general partner.

·

References to “SGP” mean Alliance Resource GP, LLC, the special general partner of Alliance Resource Partners, L.P., also referred to as our special general partner.

·

References to “Intermediate Partnership” mean Alliance Resource Operating Partners, L.P., the intermediate partnership of Alliance Resource Partners, L.P., also referred to as our intermediate partnership.

·

References to “Alliance Coal” mean Alliance Coal, LLC, the holding company for the operations of Alliance Resource Operating Partners, L.P., also referred to as our operating subsidiary.

·

References to “AHGP” mean Alliance Holdings GP, L.P., individually as the parent company, and not on a consolidated basis.

·

References to “AGP” mean Alliance GP, LLC, the general partner of Alliance Holdings GP, L.P.

 

Summary

 

We are a diversified producer and marketer of coal primarily to major United States (“U.S.”) utilities and industrial users. We began mining operations in 1971 and, since then, have grown through acquisitions and internal development to become the third largest coal producer in the eastern U.S. We operate ten underground mining complexes in Illinois, Indiana, Kentucky, Maryland and West Virginia and we operate a coal loading terminal on the Ohio River at Mt. Vernon, Indiana.  The development of an additional mine (the “Gibson South mine”) at our southern Indiana Gibson County Coal, LLC mining complex (“Gibson County Coal”) continues and includes incidental production which began in April 2014.  Also, we own a preferred equity interest and are making additional equity investments in White Oak Resources LLC (“White Oak”) and are purchasing and funding development of reserves and have constructed and are operating surface facilities at White Oak’s new longwall mining complex in southern Illinois.  As is customary in the coal industry, we have entered into long-term coal supply agreements with many of our customers.

 

We have four reportable segments: Illinois Basin, Appalachia, White Oak and Other and Corporate.  The first two reportable segments correspond to major coal producing regions in the eastern U.S.  Factors similarly affecting financial performance of our operating segments within each of these two reportable segments generally include coal quality, geology, coal marketing opportunities, mining and transportation methods and regulatory issues.  The White Oak segment includes our activities associated with the White Oak longwall Mine No. 1 development project in southern Illinois more fully described below.

 

·                 Illinois Basin reportable segment is comprised of multiple operating segments, including Webster County Coal, LLC’s Dotiki mining complex (“Dotiki”), Gibson County Coal, which includes the Gibson North mine and Gibson South mine, Hopkins County Coal, LLC mining complex (“Hopkins”), which includes the Elk Creek mine and the Fies property, White County Coal, LLC’s Pattiki mining complex (“Pattiki”), Warrior Coal, LLC’s mining complex (“Warrior”), Sebree Mining, LLC’s mining complex (“Sebree”), which includes the Onton mine, Steamport, LLC and certain undeveloped coal reserves, River View Coal, LLC’s mining complex (“River View”), CR Services, LLC, and certain properties of Alliance Resource Properties, LLC

 

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(“Alliance Resource Properties”), ARP Sebree, LLC and ARP Sebree South, LLC.  The development of the Gibson South mine continues and includes incidental production which began in April 2014.  We are in the process of permitting the Sebree and Fies properties for future mine development.

 

·                 Appalachian reportable segment is comprised of multiple operating segments, including the Mettiki mining complex (“Mettiki”), the Tunnel Ridge, LLC mining complex (“Tunnel Ridge”), the MC Mining, LLC mining complex (“MC Mining”) and the Penn Ridge Coal, LLC (“Penn Ridge”) property.  The Mettiki mining complex includes Mettiki Coal (WV), LLC’s Mountain View mine, Mettiki Coal, LLC’s preparation plant and a small third-party mining operation which has been idled since July 2013.  We are in the process of permitting the Penn Ridge property for future mine development.

 

·                 White Oak reportable segment is comprised of two operating segments, Alliance WOR Properties, LLC (“WOR Properties”) and Alliance WOR Processing, LLC (“WOR Processing”).  WOR Properties owns reserves acquired from White Oak and is committed to acquiring additional reserves from White Oak under lease-back arrangements.  WOR Properties has also provided, and is continuing to provide, certain funding to White Oak for development of these reserves.  WOR Processing includes both the surface operations at White Oak and the equity investments we are making in White Oak.  The White Oak reportable segment also includes a loan to White Oak from our Intermediate Partnership to construct certain surface facilities. For more information on White Oak, please read “Item 1. Financial Statements (Unaudited) – Note 6. White Oak Transactions” of this Quarterly Report on Form 10-Q.

 

·                 Other and Corporate segment includes marketing and administrative expenses, Alliance Service, Inc. (“ASI”) and its subsidiary, Matrix Design Group, LLC (“Matrix Design”), Alliance Design Group, LLC, ASI’s ownership of aircraft, the Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) dock activities, coal brokerage activity, our equity investment in Mid-America Carbonates, LLC (“MAC”), certain activities of Alliance Resource Properties and the Pontiki Coal, LLC mining complex (“Pontiki”) which ceased operations in November 2013 and sold most of its assets in May 2014.

 

As a result of a change in our reportable segments in 2014, certain reclassifications of 2013 segment information have been made to conform to the 2014 presentation.  These reclassifications include changes to the Appalachian reportable segment and Other and Corporate segment.

 

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

 

We reported record net income of $137.7 million for the three months ended June 30, 2014 (“2014 Quarter”) compared to $104.1 million for the three months ended June 30, 2013 (“2013 Quarter”). This increase of $33.6 million was principally due to record sales volumes, which rose to 10.4 million tons sold in the 2014 Quarter compared to 9.8 million tons sold in the 2013 Quarter.  The increase in tons sold resulted from increased volumes at our Tunnel Ridge mine, the start-up of coal production at our Gibson South mine and increased sales at our Dotiki, Gibson North, River View and MC Mining mines.  Although we had record tons sold, coal production volumes decreased 3.5% to 9.8 million tons in the 2014 Quarter, primarily due to the Warrior mine’s continued transition to a new mining area and the absence of production at our Pontiki mine.  Higher operating expenses during the 2014 Quarter primarily resulted from increased sales volumes, which particularly impacted sales-related expenses, and sales from coal inventories compared to the 2013 Quarter.

 

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Table of Contents

 

 

 

Three Months Ended June 30,

 

 

2014

 

2013

 

2014

 

2013

 

 

(in thousands)

 

(per ton sold)

Tons sold

 

10,362

 

9,817

 

N/A

 

N/A

 

Tons produced

 

9,761

 

10,120

 

N/A

 

N/A

 

Coal sales

 

$575,191

 

$541,574

 

$55.51

 

$55.17

 

Operating expenses and outside coal purchases

 

$352,895

 

$348,227

 

$34.06

 

$35.47

 

 

Coal sales.  Coal sales for the 2014 Quarter increased 6.2% to $575.2 million from $541.6 million for the 2013 Quarter.  The increase of $33.6 million in coal sales reflected the benefit of record tons sold (contributing $30.1 million in additional coal sales) and higher average coal sales prices (contributing $3.5 million in coal sales).  Average coal sales prices increased $0.34 per ton sold in the 2014 Quarter to $55.51 per ton sold as compared to $55.17 per ton sold in the 2013 Quarter, primarily as a result of higher priced coal sales at our Mettiki and Tunnel Ridge mines.

 

Operating expenses and outside coal purchases.  Operating expenses and outside coal purchases increased slightly to $352.9 million for the 2014 Quarter from $348.2 million for the 2013 Quarter, primarily due to increased coal sales volumes.  On a per ton basis, operating expenses and outside coal purchases decreased 4.0% to $34.06 per ton sold primarily due to the favorable impact of increased lower-cost production at our Tunnel Ridge mine, reduced cost per ton at our Dotiki and MC Mining mines and the absence of higher cost production at our Pontiki mine discussed above.  Operating expenses were impacted by various other factors in addition to record sales volumes, the most significant of which are discussed below:

 

·    Workers compensation expenses per ton produced decreased to $0.30 per ton in the 2014 Quarter from $0.69 per ton in the 2013 Quarter.  The decrease of $0.39 per ton produced resulted primarily from favorable claim trends offset partially by a decrease in the discount rate used to calculate the estimated present value of future obligations;

 

·    Contract mining expenses decreased $1.9 million in the 2014 Quarter compared to the 2013 Quarter.  The decrease reflects lower production from a third-party mining operation in our Appalachian region due to reduced metallurgical coal export market opportunities;

 

·    Operating expenses for the 2014 Quarter benefited from insurance proceeds of $7.0 million related to claims from the adverse geological event at the Onton mine in the third quarter of 2013; and

 

·    Operating expenses also benefited in the 2014 Quarter from a gain of $4.4 million recognized on the sale of Pontiki’s assets.  In May 2014, Pontiki completed the sale of most of its assets, including certain coal reserves, mining equipment and infrastructure and surface facilities.  In consideration for the purchase, the buyer assumed certain liabilities of Pontiki, including asset retirement obligations and agreed to pay Pontiki an overriding royalty for coal mined from the acquired reserves and certain additional fees on a per ton basis for future coal processing.  The buyer’s additional fees on a per ton basis have agreed upon minimum amounts which we recorded as a receivable in our condensed consolidated balance sheet and is reflected in the gain discussed above.

 

Operating expenses and outside coal purchases per ton decreases discussed above were offset partially by the following increases:

 

·    Labor and benefit expenses per ton produced, excluding workers’ compensation, increased 2.3% to $11.77 per ton in the 2014 Quarter from $11.50 per ton in the 2013 Quarter.  This increase of $0.27 per ton was primarily attributable to decreased production discussed above, higher labor cost per ton resulting from decreased coal recoveries at our Warrior mine due to its continued transition to a new mining area, higher cost per ton incidental production during the development phase of our Gibson South mine and the timing of mine vacation days;

 

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Table of Contents

 

·    Materials and supplies expenses per ton produced increased 1.6% to $11.71 per ton in the 2014 Quarter from $11.52 per ton in the 2013 Quarter.  The increase of $0.19 per ton produced resulted primarily from decreased production discussed above and an increase in cost for certain products and services, primarily ventilation-related materials and supplies (increase of $0.32 per ton), various preparation plant expenses (increase of $0.13 per ton) and power and fuel used in the mining process (increase of $0.15 per ton) offset partially by lower longwall subsidence expense (decrease of $0.26 per ton) and contract labor used in the mining process (decrease of $0.17 per ton); and

 

·    Operating expenses increased due to a significant reduction in coal inventory for the 2014 Quarter reflecting higher coal sales, whereas the 2013 Quarter experienced an increase in coal inventory.  Increased operating expense due to the significant reduction in coal inventory was partially offset by the benefit of lower cost per ton beginning coal inventory for the 2014 Quarter, particularly in the Appalachian region.

 

Other sales and operating revenues.  Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, Matrix Design sales, throughput fees received from White Oak and other outside services and administrative services revenue from affiliates.  Other sales and operating revenues increased to $17.6 million in the 2014 Quarter from $7.0 million in the 2013 Quarter.  The increase of $10.6 million was primarily due to increased White Oak throughput fees and payments in lieu of shipments received from a customer in the 2014 Quarter related to an Appalachian coal sales contract.

 

Depreciation, depletion and amortization.  Depreciation, depletion and amortization expense decreased to $67.1 million for the 2014 Quarter from $68.2 million for the 2013 Quarter.  The decrease of $1.1 million was attributable to the extension of the Mettiki mine’s expected life due to the acquisition of additional coal reserves during 2013 as well as the closure of the Pontiki mining complex in late 2013, offset in part by depreciation increases related to increased sales volumes mentioned above, as well as capital expenditures related to production expansion and infrastructure investments at various operations.

 

General and administrative.  General and administrative expense for the 2014 Quarter increased to $19.8 million compared to $16.6 million in the 2013 Quarter.  The increase of $3.2 million was primarily due to higher incentive compensation expenses and other professional services.

 

Interest expense.  Interest expense, net of capitalized interest, increased to $8.7 million for the 2014 Quarter from $6.2 million for the 2013 Quarter.  The increase of $2.5 million in the 2014 Quarter was principally attributable to lower capitalized interest on our equity investment in White Oak.  Interest payable under our term loan and revolving credit facility is discussed below under “–Debt Obligations.”

 

Equity in loss of affiliates, net.  Equity in loss of affiliates, net includes our equity investments in MAC and White Oak.  For the 2014 Quarter, equity in loss of affiliates was $7.4 million compared to $5.7 million for the 2013 Quarter, which was primarily attributable to losses allocated to us from our equity investment in White Oak.

 

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Table of Contents

 

Segment Adjusted EBITDA.  Our 2014 Quarter Segment Adjusted EBITDA increased $37.8 million, or 19.4%, to a record $232.8 million from the 2013 Quarter Segment Adjusted EBITDA of $195.0 million.  Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are (in thousands):

 

 

 

Three Months Ended
June 30,

 

 

 

 

 

 

 

 

2014

 

2013

 

Increase/(Decrease)

Segment Adjusted EBITDA

 

 

 

 

 

 

 

 

 

 

 

 

Illinois Basin

 

 $

165,859

 

 

 $

164,623

 

 

 $

1,236

 

 

0.8%

 

Appalachia

 

67,089

 

 

34,120

 

 

32,969

 

 

96.6%

 

White Oak

 

(4,915

)

 

(6,295

)

 

1,380

 

 

21.9%

 

Other and Corporate

 

4,774

 

 

2,579

 

 

2,195

 

 

85.1%

 

Elimination

 

-

 

 

-

 

 

-

 

 

-

 

Total Segment Adjusted EBITDA (2)

 

 $ 

232,807

 

 

 $

195,027

 

 

 $ 

37,780

 

 

19.4%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Tons sold

 

 

 

 

 

 

 

 

 

 

 

 

Illinois Basin

 

8,014

 

 

7,547

 

 

467

 

 

6.2%

 

Appalachia

 

2,348

 

 

2,091

 

 

257

 

 

12.3%

 

White Oak

 

-

 

 

-

 

 

-

 

 

-

 

Other and Corporate

 

-

 

 

195

 

 

(195

)

 

(1

)

Elimination

 

-

 

 

(16

)

 

16

 

 

(1

)

Total tons sold

 

10,362

 

 

9,817

 

 

545

 

 

5.6%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coal sales

 

 

 

 

 

 

 

 

 

 

 

 

Illinois Basin

 

 $

420,924

 

 

 $

397,364

 

 

 $

23,560

 

 

5.9%

 

Appalachia

 

154,107

 

 

129,688

 

 

24,419

 

 

18.8%

 

White Oak

 

-

 

 

-

 

 

-

 

 

-

 

Other and Corporate

 

160

 

 

15,530

 

 

(15,370

)

 

(99.0)%

 

Elimination

 

-

 

 

(1,008

)

 

1,008

 

 

(1

)

Total coal sales

 

 $ 

575,191

 

 

 $

541,574

 

 

 $

33,617

 

 

6.2%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other sales and operating revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

Illinois Basin

 

 $

877

 

 

 $

963

 

 

 $

(86

)

 

(8.9)%

 

Appalachia

 

6,900

 

 

984

 

 

5,916

 

 

(1

)

White Oak

 

4,169

 

 

-

 

 

4,169

 

 

(1

)

Other and Corporate

 

8,030

 

 

8,993

 

 

(963

)

 

(10.7)%

 

Elimination

 

(2,415

)

 

(3,914

)

 

1,499

 

 

38.3%

 

Total other sales and operating revenues

 

 $

17,561

 

 

 $

7,026

 

 

 $

10,535

 

 

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Segment Adjusted EBITDA Expense

 

 

 

 

 

 

 

 

 

 

 

 

Illinois Basin

 

 $

255,942

 

 

 $

233,703

 

 

 $

22,239

 

 

9.5%

 

Appalachia

 

93,917

 

 

96,553

 

 

(2,636

)

 

(2.7)%

 

White Oak

 

1,625

 

 

427

 

 

1,198

 

 

(1

)

Other and Corporate

 

3,503

 

 

22,113

 

 

(18,610

)

 

(84.2)%

 

Elimination

 

(2,415

)

 

(4,922

)

 

2,507

 

 

50.9%

 

Total Segment Adjusted EBITDA Expense (3)

 

 $

352,572

 

 

 $

347,874

 

 

 $

4,698

 

 

1.4%

 

 

(1)  Percentage change was greater than or equal to 100%.

 

(2)  Segment Adjusted EBITDA, which is not a generally accepted accounting principles (“GAAP”) financial measure, is defined as net income before net interest expense, income taxes, depreciation, depletion and amortization and general and administrative expenses.  Segment Adjusted EBITDA is a key component of consolidated EBITDA, which is used as a supplemental financial measure by management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

 

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·

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

·

the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

·

our operating performance and return on investment compared to those of other companies in the coal energy sector, without regard to financing or capital structures; and

·

the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

 

Segment Adjusted EBITDA is also used as a supplemental financial measure by our management for reasons similar to those stated in the previous explanation of EBITDA.  In addition, the exclusion of corporate general and administrative expenses from consolidated Segment Adjusted EBITDA allows management to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments.

 

The following is a reconciliation of consolidated Segment Adjusted EBITDA to net income, the most comparable GAAP financial measure (in thousands):

 

 

 

Three Months Ended
June 30,

 

 

2014

 

2013

 

 

 

 

 

 

 

Segment Adjusted EBITDA

 

 $

232,807

 

 

 $

195,027

 

 

 

 

 

 

 

 

General and administrative

 

(19,771

)

 

(16,597

)

Depreciation, depletion and amortization

 

(67,052

)

 

(68,207

)

Interest expense, net

 

(8,331

)

 

(6,040

)

Income tax expense

 

-

 

 

(109

)

Net income

 

 $

137,653

 

 

 $

104,074

 

 

(3)      Segment Adjusted EBITDA Expense (a non-GAAP financial measure) includes operating expenses, outside coal purchases and other income.  Transportation expenses are excluded as these expenses are passed through to our customers and, consequently, we do not realize any gain or loss on transportation revenues.  Segment Adjusted EBITDA Expense is used as a supplemental financial measure by our management to assess the operating performance of our segments.  Segment Adjusted EBITDA Expense is a key component of Segment Adjusted EBITDA in addition to coal sales and other sales and operating revenues.  The exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA Expense allows management to focus solely on the evaluation of segment operating performance as it primarily relates to our operating expenses.  Outside coal purchases are included in Segment Adjusted EBITDA Expense because tons sold and coal sales include sales from outside coal purchases.

 

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The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to operating expense, the most comparable GAAP financial measure (in thousands):

 

 

 

Three Months Ended

 

 

 

June 30,

 

 

 

2014

 

2013

 

 

 

 

 

 

 

Segment Adjusted EBITDA Expense

 

 $

352,572

 

 $

347,874

 

 

 

 

 

 

 

Outside coal purchases

 

(2)

 

(790)

 

Other income

 

323

 

353

 

Operating expenses (excluding depreciation, depletion and amortization)

 

 $

352,893

 

 $

347,437

 

 

Illinois Basin – Segment Adjusted EBITDA increased 0.8% to $165.9 million in the 2014 Quarter from $164.6 million in the 2013 Quarter.  The increase of $1.2 million was primarily attributable to increased tons sold, which increased 6.2% to 8.0 million tons in the 2014 Quarter.  Coal sales increased 5.9% to $420.9 million compared to $397.4 million in the 2013 Quarter. The increase of $23.5 million reflects increased tons produced and sold from our Dotiki, River View and Gibson North mines and the start-up of production at the Gibson South mine in April 2014, offset partially by a slightly lower average coal sales price of $52.52 per ton sold during the 2014 Quarter compared to $52.65 per ton sold in the 2013 Quarter.  Segment Adjusted EBITDA Expense increased 9.5% to $255.9 million in the 2014 Quarter from $233.7 million in the 2013 Quarter and increased $0.98 per ton sold to $31.94 from $30.96 per ton sold in the 2013 Quarter, primarily due to lower recoveries at our Warrior mine as it continues to transition into a new mining area and the start-up of higher cost development production at the Gibson South mine discussed above, as well as certain cost increases described above under “–Operating expenses and outside coal purchases.”  The increase in Segment Adjusted EBITDA Expense was partially offset by insurance proceeds received in the 2014 Quarter related to the adverse geological event at our Onton mine in the third quarter of 2013.

 

Appalachia – Segment Adjusted EBITDA increased 96.6% to $67.1 million for the 2014 Quarter from $34.1 million in the 2013 Quarter.  The increase of $33.0 million was primarily attributable to increased tons sold, which increased 12.3% to 2.3 million tons sold in the 2014 Quarter, as well as a higher average coal sales price of $65.61 per ton sold during the 2014 Quarter compared to $62.03 per ton sold in the 2013 Quarter.  Coal sales increased 18.8% to $154.1 million compared to $129.7 million in the 2013 Quarter.  The increase of $24.4 million was primarily due to increased production at our Tunnel Ridge and MC Mining mines.   Segment Adjusted EBITDA also benefited from increased other sales and operating revenues due to payments in lieu of shipments received from a customer in the 2014 Quarter.  Segment Adjusted EBITDA Expense decreased 2.7% to $93.9 million in the 2014 Quarter from $96.6 million in the 2013 Quarter and decreased $6.19 per ton sold to $39.99 per ton sold compared to $46.18 per ton sold in the 2013 Quarter, primarily due to improved productivity and geological conditions at our Tunnel Ridge mine and new Excel No. 4 mining area at the MC Mining operation, reduced contract mining expenses and lower employee benefit costs at our Mettiki mining complex and lower workers’ compensation expense across the region.

 

White Oak – Segment Adjusted EBITDA was $(4.9) million and $(6.3) million, respectively, in the 2014 and 2013 Quarters and was primarily attributable to losses allocated to us from our equity interest in White Oak, partially offset by increased throughput fees earned from White Oak.  For more information on White Oak, please read “Item 1. Financial Statements (Unaudited) – Note 6. White Oak Transactions” of this Quarterly Report on Form 10-Q.

 

Other and Corporate – Segment Adjusted EBITDA increased $2.2 million in the 2014 Quarter from the 2013 Quarter.  This increase was primarily attributable to a $4.4 million gain on the sale of most of Pontiki’s assets in the 2014 Quarter discussed above.  Segment Adjusted EBITDA Expense decreased 84.2% to $3.5 million for the 2014 Quarter, primarily due to the absence of production costs at our Pontiki mine discussed above.

 

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Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

 

We reported record net income of $253.6 million for the six months ended June 30, 2014 (“2014 Period”) compared to $207.0 million for the six months ended June 30, 2013 (“2013 Period”). This increase of $46.6 million was principally due to record coal sales and production volumes.  We had tons sold of 19.9 million tons and tons produced of 20.0 million tons in the 2014 Period compared to 19.5 million tons sold and 19.9 million tons produced in the 2013 Period.  The increase in tons sold and produced resulted primarily from increased production from improved mining conditions and recoveries at our Tunnel Ridge, MC Mining and Dotiki mines and the start-up of coal production at our Gibson South mine.  Lower operating expenses during the 2014 Period resulted primarily from reduced expenses per ton at our Tunnel Ridge, MC Mining and Dotiki mines, in addition to a significant increase in sales of lower cost production from Tunnel Ridge, the idling of a higher cost third-party mining operation at our Mettiki mine and the absence of higher cost production at our Pontiki mine.

 

 

 

Six Months Ended June 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

(in thousands)

 

(per ton sold)

 

Tons sold

 

19,857

 

19,515

 

N/A

 

N/A

 

Tons produced

 

20,014

 

19,939

 

N/A

 

N/A

 

Coal sales

 

$

1,100,736

 

$

1,076,083

 

$

55.43

 

$

55.14

 

Operating expenses and outside coal purchases

 

$

675,139

 

$

697,404

 

$

34.00

 

$

35.74

 

 

Coal sales.  Coal sales for the 2014 Period increased 2.3% to $1.10 billion from $1.08 billion for the 2013 Period.  The increase of $24.7 million in coal sales reflected the benefit of record tons sold (contributing $18.9 million in additional coal sales) and higher average coal sales prices (contributing $5.8 million in coal sales).  Average coal sales prices increased $0.29 per ton sold to $55.43 per ton in the 2014 Period as compared to $55.14 per ton sold in the 2013 Period, primarily as a result of higher priced coal sales at our Mettiki mine.

 

Operating expenses and outside coal purchases.  Operating expenses and outside coal purchases decreased 3.2% to $675.1 million for the 2014 Period from $697.4 million for the 2013 Period, primarily due to the favorable impact of increased lower-cost production at our Tunnel Ridge mine, reduced cost per ton at our Dotiki and MC Mining mines and the absence of higher cost production at our Pontiki mine discussed above.  On a per ton basis, operating expenses and outside coal purchases decreased 4.9% to $34.00 per ton sold.  Operating expenses were impacted by various other factors, in addition to the impact of record production volumes.  The most significantly impacted expenses are discussed below:

 

·

Labor and benefit expenses per ton produced, excluding workers’ compensation, decreased 1.4% to $11.42 per ton in the 2014 Period from $11.58 per ton in the 2013 Period. This decrease of $0.16 per ton was primarily attributable to lower labor cost per ton resulting from increased coal production and improved recoveries discussed above;

 

 

·

Workers compensation expenses per ton produced decreased to $0.38 per ton in the 2014 Period from $0.71 per ton in the 2013 Period. The decrease of $0.33 per ton produced resulted primarily from favorable claim trends offset partially by a decrease in the discount rate used to calculate the estimated present value of future obligations;

 

 

·

Material and supplies expenses per ton produced decreased 1.3% to $11.32 per ton in the 2014 Period from $11.47 per ton in the 2013 Period. The decrease of $0.15 per ton produced resulted primarily from increased coal production discussed above and a decrease in cost for certain products and services, primarily contract labor used in the mining process (decrease of

 

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$0.29 per ton) and lower longwall subsidence expense (decrease of $0.12 per ton), partially offset by an increase in certain ventilation related materials and supplies expenses (increase of $0.15 per ton);

 

 

·

Contract mining expenses decreased $3.9 million for the 2014 Period compared to the 2013 Period. The decrease reflects lower production from a third-party mining operation in our Appalachian region due to reduced metallurgical coal export market opportunities;

 

 

·

Outside coal purchases decreased $1.4 million for the 2014 Period compared to the 2013 Period. The decrease of $1.4 million was primarily attributable to decreased coal brokerage activity and less coal purchased for sale into the metallurgical export markets. The cost per ton to purchase coal is typically higher than our cost per ton to produce coal, thus significantly lower volumes of coal purchases, like in the 2014 Period, generally reduce our overall total expenses per ton;

 

 

·

Operating expenses benefited from insurance proceeds of $7.0 million related to claims from the adverse geological event at the Onton mine in the third quarter of 2013; and

 

 

·

Operating expenses also benefited in the 2014 Period due to a gain of $4.4 million recognized on the sale of Pontiki’s assets in May 2014 discussed above.

 

Other sales and operating revenues.  Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, Matrix Design sales, throughput fees received from White Oak and other outside services and administrative services revenue from affiliates.  Other sales and operating revenues increased to $28.0 million for the 2014 Period from $13.6 million for the 2013 Period.  The increase of $14.4 million was primarily attributable to increased White Oak throughput fees and payments in lieu of shipments received from a customer in the 2014 Period related to an Appalachian coal sales contract.

 

General and administrative.  General and administrative expenses for the 2014 Period increased to $37.2 million compared to $31.8 million in the 2013 Period.  The increase of $5.4 million was primarily due to higher incentive compensation expenses and other professional services.

 

Depreciation, depletion and amortization.  Depreciation, depletion and amortization expense increased to $133.9 million for the 2014 Period from $132.6 million for the 2013 Period.  The increase of $1.3 million was attributable to additional depreciation related to increased sales volumes discussed above and capital expenditures related to production expansion and infrastructure investments at various operations, offset partially by the extension of the Mettiki mine’s expected life due to the acquisition of additional coal reserves during 2013 as well as the closure of the Pontiki mining complex in late 2013.

 

Interest expense.  Interest expense, net of capitalized interest, increased to $16.8 million for the 2014 Period from $12.8 million for the 2013 Period.  The increase of $4.0 million was principally attributable to lower capitalized interest on our equity investment in White Oak.  Interest payable under our term loan and revolving credit facility is discussed below under “–Debt Obligations.”

 

Equity in loss of affiliates, net.  Equity in loss of affiliates, net includes our equity investments in MAC and White Oak.  For the 2014 Period, equity in loss of affiliates was $13.6 million compared to $9.6 million for the 2013 Period, which was primarily attributable to losses allocated to us due to our equity investment in White Oak.

 

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Segment Adjusted EBITDA.  Our 2014 Period Segment Adjusted EBITDA increased $57.3 million, or 14.9%, to $440.7 million from the 2013 Period Segment Adjusted EBITDA of $383.4 million.  Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are (in thousands):

 

 

 

Six Months Ended
June 30,

 

 

 

 

 

 

 

2014

 

2013

 

Increase/(Decrease)

 

Segment Adjusted EBITDA

 

 

 

 

 

 

 

 

 

Illinois Basin

 

 $

329,508

 

 $

331,844

 

 $

(2,336)

 

(0.7)%

 

Appalachia

 

115,959

 

57,077

 

58,882

 

(1)

 

White Oak

 

(8,912)

 

(10,587)

 

1,675

 

15.8%

 

Other and Corporate

 

4,106

 

5,044

 

(938)

 

(18.6)%

 

Elimination

 

-

 

-

 

-

 

-

 

Total Segment Adjusted EBITDA (2)

 

 $

440,661

 

 $

383,378

 

 $

57,283

 

14.9%

 

 

 

 

 

 

 

 

 

 

 

Tons sold

 

 

 

 

 

 

 

 

 

Illinois Basin

 

15,496

 

15,253

 

243

 

1.6%

 

Appalachia

 

4,361

 

3,874

 

487

 

12.6%

 

White Oak

 

-

 

-

 

-

 

-

 

Other and Corporate

 

-

 

437

 

(437)

 

(1)

 

Elimination

 

-

 

(49)

 

49

 

(1)

 

Total tons sold

 

19,857

 

19,515

 

342

 

1.8%

 

 

 

 

 

 

 

 

 

 

 

Coal sales

 

 

 

 

 

 

 

 

 

Illinois Basin

 

 $

813,178

 

 $

797,684

 

 $

15,494

 

1.9%

 

Appalachia

 

287,398

 

247,432

 

39,966

 

16.2%

 

White Oak

 

-

 

-

 

-

 

-

 

Other and Corporate

 

160

 

34,052

 

(33,892)

 

(99.5)%

 

Elimination

 

-

 

(3,085)

 

3,085

 

(1)

 

Total coal sales

 

 $

1,100,736

 

 $

1,076,083

 

 $

24,653

 

2.3%

 

 

 

 

 

 

 

 

 

 

 

Other sales and operating revenues

 

 

 

 

 

 

 

 

 

Illinois Basin

 

 $

1,863

 

 $

2,008

 

 $

(145)

 

(7.2)%

 

Appalachia

 

8,051

 

2,123

 

5,928

 

(1)

 

White Oak

 

7,867

 

-

 

7,867

 

(1)

 

Other and Corporate

 

15,771

 

16,978

 

(1,207)

 

(7.1)%

 

Elimination

 

(5,503)

 

(7,471)

 

1,968

 

26.3%

 

Total other sales and operating revenues

 

 $

28,049

 

 $

13,638

 

 $

14,411

 

(1)

 

 

 

 

 

 

 

 

 

 

 

Segment Adjusted EBITDA Expense

 

 

 

 

 

 

 

 

 

Illinois Basin

 

 $

485,533

 

 $

467,848

 

 $

17,685

 

3.8%

 

Appalachia

 

179,490

 

192,478

 

(12,988)

 

(6.7)%

 

White Oak

 

3,016

 

528

 

2,488

 

(1)

 

Other and Corporate

 

11,974

 

46,479

 

(34,505)

 

(74.2)%

 

Elimination

 

(5,503)

 

(10,556)

 

5,053

 

47.9%

 

Total Segment Adjusted EBITDA Expense (3)

 

 $

674,510

 

 $

696,777

 

 $

(22,267)

 

(3.2)%

 

 

(1)

Percentage change was greater than or equal to 100%.

 

 

(2)

Segment Adjusted EBITDA (a non-GAAP financial measure) is defined as net income before net interest expense, income taxes, depreciation, depletion and amortization and general and administrative expenses.  Segment Adjusted EBITDA is a key component of consolidated EBITDA, which is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess:

 

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·

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

·

the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

·

our operating performance and return on investment compared to those of other companies in the coal energy sector, without regard to financing or capital structures; and

·

the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

 

Segment Adjusted EBITDA is also used as a supplemental financial measure by our management for reasons similar to those stated in the previous explanation of consolidated EBITDA.  In addition, the exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA allows management to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses which are primarily controlled by our segments.

 

The following is a reconciliation of consolidated Segment Adjusted EBITDA to net income, the most comparable GAAP financial measure (in thousands):

 

 

 

Six Months Ended

 

 

 

June 30,

 

 

 

2014

 

2013

 

 

 

 

 

 

 

Segment Adjusted EBITDA

 

  $

440,661

 

  $

383,378

 

 

 

 

 

 

 

General and administrative

 

(37,206)

 

(31,843)

 

Depreciation, depletion and amortization

 

(133,893)

 

(132,589)

 

Interest expense, net

 

(16,005)

 

(12,524)

 

Income tax benefit

 

-

 

589

 

Net income

 

  $

253,557

 

  $

207,011

 

 

(3)

Segment Adjusted EBITDA Expense (a non-GAAP financial measure) includes operating expenses, outside coal purchases and other income.  Transportation expenses are excluded as these expenses are passed through to our customers and, consequently, we do not realize any gain or loss on transportation revenues.  Segment Adjusted EBITDA Expense is used as a supplemental financial measure by our management to assess the operating performance of our segments.  Segment Adjusted EBITDA Expense is a key component of Segment Adjusted EBITDA in addition to coal sales and other sales and operating revenues.  The exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA Expense allows management to focus solely on the evaluation of segment operating performance as it primarily relates to our operating expenses.  Outside coal purchases are included in Segment Adjusted EBITDA Expense because tons sold and coal sales include sales from outside coal purchases.

 

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The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to operating expense, the most comparable GAAP financial measure (in thousands):

 

 

 

Six Months Ended

 

 

 

June 30,

 

 

 

2014

 

2013

 

 

 

 

 

 

 

Segment Adjusted EBITDA Expense

 

 $

674,510

 

 $

696,777

 

 

 

 

 

 

 

Outside coal purchases

 

(4)

 

(1,392)

 

Other income

 

629

 

627

 

Operating expenses (excluding depreciation, depletion and amortization)

 

 $

675,135

 

 $

696,012

 

 

Illinois Basin – Segment Adjusted EBITDA decreased slightly to $329.5 million in the 2014 Period from $331.8 million in the 2013 Period.  The decrease of $2.3 million was primarily attributable to decreased coal recoveries at our Warrior mine as it continues to transition into a new mining area and increased expenses per ton from our Pattiki and Hopkins mines due to difficult mining conditions, partially offset by a strong sales and production performance from our Dotiki mine.  The 2014 Period benefited from increased tons sold, which increased 1.6% to 15.5 million tons in the 2014 Period, as well as a higher average coal sales price of $52.48 per ton sold compared to $52.30 for the 2013 Period.  Coal sales increased 1.9% to $813.2 million in the 2014 Period compared to $797.7 million in the 2013 Period.  The increase of $15.5 million primarily reflects increased tons sold from our River View and Dotiki mines and the start-up of production at the Gibson South mine in April 2014.  Segment Adjusted EBITDA Expense increased 3.8% to $485.5 million in the 2014 Period from $467.8 million in the 2013 Period and increased $0.66 per ton sold to $31.33 from $30.67 per ton sold in the 2013 Period, primarily as a result of difficult mining conditions at our Pattiki and Hopkins mines, lower recoveries at our Warrior mine as it continues to transition into a new mining area and the start-up of high cost development production at the Gibson South mine discussed above. The increase in Segment Adjusted EBITDA Expense was partially offset by insurance proceeds received in the 2014 Period related to the impact of an adverse geological event at our Onton mine in the third quarter of 2013, as well as certain other cost decreases discussed above under “–Operating expenses and outside coal purchases.”

 

Appalachia – Segment Adjusted EBITDA increased to $116.0 million for the 2014 Period as compared to $57.1 million for the 2013 Period.  The increase of $58.9 million was primarily attributable to increased tons sold, which increased 12.6% to 4.4 million tons in the 2014 Period compared to 3.9 million tons in the 2013 Period, as well as a higher average coal sales price of $65.90 per ton sold during the 2014 Period compared to $63.87 per ton sold in the 2013 Period.  Coal sales increased 16.2% to $287.4 million in the 2014 Period compared to $247.4 million in the 2013 Period.  The increase of $40.0 million was primarily due to increased production at our Tunnel Ridge and MC Mining mining operations and higher priced coal sales at our Mettiki mine.  Segment Adjusted EBITDA also benefited from increased other sales and operating revenues due to payments in lieu of shipments received from a customer in the 2014 Period.  Segment Adjusted EBITDA Expense decreased 6.7% to $179.5 million in the 2014 Period from $192.5 million in the 2013 Period and decreased $8.53 per ton sold to $41.16 from $49.69 per ton sold in the 2013 Period, primarily due to improved productivity and geological conditions at our Tunnel Ridge mine and new Excel No. 4 mining area at the MC Mining operation, reduced contract mining expenses and lower employee benefit cost at our Mettiki mining complex and lower workers’ compensation expense across the region, as well as certain other cost decreases discussed above under “–Operating expenses and outside coal purchases.”

 

White Oak – Segment Adjusted EBITDA was $(8.9) million and $(10.6) million in the 2014 and 2013 Periods, respectively, primarily attributable to losses allocated to us due to our equity interest in White Oak, partially offset by increased throughput fees earned from White Oak.  For more information on White Oak, please read “Item 1. Financial Statements (Unaudited) – Note 6. White Oak Transactions” of this Quarterly Report on Form 10-Q.

 

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Other and Corporate – Segment Adjusted EBITDA decreased $0.9 million in the 2014 Period from the 2013 Period.  This decrease was primarily attributable to the cessation of operations at our Pontiki mine in November 2013, partially offset by a $4.4 million gain on the sale of Pontiki’s assets in the 2014 Period discussed above.  Segment Adjusted EBITDA Expense decreased 74.2% to $12.0 million from $46.5 million for the 2014 Period, primarily due to the absence of production costs at our Pontiki mine discussed above.

 

Liquidity and Capital Resources

 

Liquidity

 

We have historically satisfied our working capital requirements and funded our capital expenditures and debt service obligations with cash generated from operations, cash provided by the issuance of debt or equity and borrowings under credit facilities.  We believe that existing cash balances, future cash flows from operations, borrowings under credit facilities and cash provided from the issuance of debt or equity will be sufficient to meet our working capital requirements, capital expenditures and additional equity investments, debt payments, commitments and distribution payments.  Our ability to satisfy our obligations and planned expenditures will depend upon our future operating performance and access to and cost of financing sources, which will be affected by prevailing economic conditions generally and in the coal industry specifically, which are beyond our control.  Based on our recent operating results, current cash position, anticipated future cash flows and sources of financing that we expect to have available, we do not anticipate any significant liquidity constraints in the foreseeable future.  However, to the extent operating cash flow or access to and cost of financing sources are materially different than expected, future liquidity may be adversely affected.  Please read “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013.

 

Cash Flows

 

Cash provided by operating activities was $379.4 million for the 2014 Period compared to $373.8 million for the 2013 Period.  The increase in cash provided by operating activities was primarily due to higher net income during the 2014 Period and an increase in accounts payable during the 2014 Period, partially offset by an increase in trade receivables during the 2014 Period as compared to a decrease during the 2013 Period and a decrease in accrued payroll and related benefits in the 2014 Period.

 

Net cash used in investing activities was $208.8 million for the 2014 Period compared to $236.0 million for the 2013 Period.  The decrease in cash used in investing activities was primarily attributable to a decrease in the acquisition and funding for development of coal reserves in the 2014 Period, lower capital expenditures for mine infrastructure and equipment at various mines, particularly at our Gibson South and Tunnel Ridge mines, and proceeds from insurance for property, plant and equipment related to claims from the adverse geological event at the Onton mine in the third quarter of 2013.  These decreases were offset by an increase in funding of the White Oak equity investment during the 2014 Period.

 

Net cash used in financing activities was $244.8 million for the 2014 Period compared to $157.3 million for the 2013 Period.  The increase in cash used in financing activities was primarily attributable to increased distributions paid to partners in the 2014 Period, as well as net payments under our revolving credit facilities during the 2014 Period and payments under our term loan in the 2014 Period, which are discussed in more detail below under “–Debt Obligations.”

 

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Capital Expenditures

 

Capital expenditures decreased slightly to $154.6 million in the 2014 Period from $163.0 million in the 2013 Period.

 

Our anticipated total capital expenditures for the year ending December 31, 2014 are estimated in a range of $320.0 million to $350.0 million, which includes expenditures for mine expansion to complete development of our new Gibson South mine, reserve acquisitions related to the White Oak mine development project and infrastructure projects and maintenance capital at various mines.  In addition to these capital expenditures, ARLP continues to anticipate funding a total of approximately $80.0 million to $95.0 million of its preferred equity investment commitment to White Oak in 2014.  Management anticipates funding remaining 2014 capital requirements with cash and cash equivalents ($19.4 million as of June 30, 2014), cash flows from operations, borrowings under the revolving credit facility and, if necessary, accessing the debt or equity capital markets.  We will continue to have significant capital requirements over the long-term, which may require us to obtain additional debt or equity capital.  The availability and cost of additional capital will depend upon prevailing market conditions, the market price of our common units and several other factors over which we have limited control, as well as our financial condition and results of operations.

 

Debt Obligations

 

Credit Facility.  On May 23, 2012, our Intermediate Partnership entered into a credit agreement (the “Credit Agreement”) with various financial institutions for a revolving credit facility (the “Revolving Credit Facility”) of $700.0 million and a term loan (the “Term Loan”) in the aggregate principal amount of $250.0 million (collectively, the Revolving Credit Facility and Term Loan are referred to as the “Credit Facility”).  Borrowings under the Credit Agreement bear interest at a Base Rate or Eurodollar Rate, at our election, plus an applicable margin that fluctuates depending upon the ratio of Consolidated Debt to Consolidated Cash Flow (each as defined in the Credit Agreement).  We have elected a Eurodollar Rate which, with applicable margin, was 1.81% on borrowings outstanding as of June 30, 2014.  The Credit Facility matures May 23, 2017, at which time all amounts outstanding are required to be repaid.  Interest is payable quarterly, with principal of the Term Loan due as follows:  commencing with the 2014 Quarter and for each quarter thereafter ending on March 31, 2016, an amount per quarter equal to 2.50% of the aggregate amount of the Term Loan advances outstanding; for each quarter beginning June 30, 2016 through December 31, 2016, 20% of the aggregate amount of the Term Loan advances outstanding; and the remaining balance of the Term Loan advances at maturity.  In June 2014, we made the first principal payment on the Term Loan, leaving a balance of $243.8 million.  We have the option to prepay the Term Loan at any time in whole or in part subject to terms and conditions described in the Credit Agreement.  Upon a “change in control” (as defined by the Credit Agreement), the unpaid principal amount of the Credit Facility, all interest thereon and all other amounts payable under the Credit Agreement would become due and payable.

 

At June 30, 2014, we had borrowings of $170.0 million and $5.4 million of letters of credit outstanding with $524.6 million available for borrowing under the Revolving Credit Facility.  We utilize the Revolving Credit Facility, as appropriate, for working capital requirements, capital expenditures and investments in affiliates, scheduled debt payments and distribution payments.  We incur an annual commitment fee of 0.25% on the undrawn portion of the Revolving Credit Facility.

 

Senior Notes.  Our Intermediate Partnership has $18.0 million principal amount of 8.31% senior notes due August 20, 2014, with interest payable semi-annually (“Senior Notes”).

 

Series A Senior Notes.  On June 26, 2008, our Intermediate Partnership entered into a Note Purchase Agreement (the “2008 Note Purchase Agreement”) with a group of institutional investors in a private placement offering.  We issued $205.0 million of Series A senior notes, which bear interest at 6.28% and mature on June 26, 2015 with interest payable semi-annually.

 

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Series B Senior Notes.  On June 26, 2008, we issued under the 2008 Note Purchase Agreement $145.0 million of Series B senior notes (together with the Series A senior notes, the “2008 Senior Notes”), which bear interest at 6.72% and mature on June 26, 2018 with interest payable semi-annually.

 

The Senior Notes, 2008 Senior Notes and the Credit Facility described above (collectively, “ARLP Debt Arrangements”) are guaranteed by all of the material direct and indirect subsidiaries of our Intermediate Partnership. The ARLP Debt Arrangements contain various covenants affecting our Intermediate Partnership and its subsidiaries restricting, among other things, the amount of distributions by our Intermediate Partnership, incurrence of additional indebtedness and liens, sale of assets, investments, mergers and consolidations and transactions with affiliates, in each case subject to various exceptions.  The ARLP Debt Arrangements also require the Intermediate Partnership to remain in control of a certain amount of mineable coal reserves relative to its annual production.  In addition, the ARLP Debt Arrangements require our Intermediate Partnership to maintain (a) debt to cash flow ratio of not more than 3.0 to 1.0 and (b) cash flow to interest expense ratio of not less than 3.0 to 1.0, in each case, during the four most recently ended fiscal quarters.  The debt to cash flow ratio and cash flow to interest expense ratio were 1.05 to 1.0 and 21.5 to 1.0, respectively, for the trailing twelve months ended June 30, 2014.  We were in compliance with the covenants of the ARLP Debt Arrangements as of June 30, 2014.

 

Other.  In addition to the letters of credit available under the Credit Facility discussed above, we also have agreements with two banks to provide additional letters of credit in an aggregate amount of $31.1 million to maintain surety bonds to secure certain asset retirement obligations and our obligations for workers’ compensation benefits.  At June 30, 2014, we had $30.7 million in letters of credit outstanding under agreements with these two banks.

 

Related-Party Transactions

 

We have continuing related-party transactions with our managing general partner, AHGP and SGP and its affiliates. These related-party transactions relate principally to the provision of administrative services to AHGP and Alliance Resource Holdings II, Inc. and their respective affiliates, mineral and equipment leases with SGP and its affiliates, and agreements relating to the use of aircraft.  We also have ongoing transactions with White Oak and related entities to support development of a longwall mining operation currently under construction.

 

Please read our Annual Report on Form 10-K for the year ended December 31, 2013, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Related-Party Transactions” for additional information concerning related-party transactions.

 

New Accounting Standards

 

New Accounting Standards Issued and Not Yet Adopted

 

In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”).  ASU 2014-08 changes the requirements for reporting discontinued operations in Accounting Standards Codification 205, Presentation of Financial Statements, by updating the criteria for determining which disposals can be presented as discontinued operations and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of discontinued operations.  ASU 2014-08 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2014.  We do not anticipate the adoption of ASU 2014-08 on January 1, 2015 will have a material impact on our consolidated financial statements.

 

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”).  ASU 2014-09 is a new revenue recognition standard that provides a five-step analysis of transactions to determine when and how revenue is recognized.  The core principle of the new standard is

 

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an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016 and shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption.  Early adoption is not permitted.  We are currently evaluating the effect of adopting ASU 2014-09 on January 1, 2017.

 

Other Information

 

IRS Notice

 

On April 12, 2013, we received a “Notice of Beginning of Administrative Proceeding” (“NBAP”) from the Internal Revenue Service notifying us of an audit of the income tax return of Alliance Coal, the holding company for the operations of our Intermediate Partnership, for the tax year ending December 31, 2011.  We believe this is a routine audit of our lower-tier subsidiary’s income, gain, deductions, losses and credits.  The audit is ongoing.

 

Unit Split

 

On June 16, 2014, we completed a two-for-one split of our common units, whereby holders of record as of May 30, 2014 received a one unit distribution on each unit outstanding on that date.  The unit split resulted in the issuance of 37,030,317 common units.  All references to the number of units and per unit net income and distribution amounts included in this report have been adjusted to give effect for this unit split for all periods presented.  Also, ARLP’s partnership agreement was amended effective June 16, 2014, to reduce the target thresholds for the incentive distribution rights per unit by half.

 

Regulation and Laws

 

Reference is made to “Item 1. Business – Regulation and Laws – Air Emissions” in our Annual Report on Form 10-K for the year ended December 31, 2013.

 

On April 29, 2014, the Supreme Court reversed the D.C. Circuit’s ruling vacating the Cross-State Air Pollution Rule (“CSAPR”), upheld the rule, and remanded the case for the D.C. Circuit to resolve the remaining implementation issues consistent with the Supreme Court’s opinion.  The Supreme Court held that the U.S. Environmental Protection Agency’s (“EPA”) allocation of emissions reductions in upwind states permissibly considered the cost-effectiveness of achieving downwind attainment and that EPA has authority under the Federal Clean Air Act (“CAA”) to impose federal implementation plans (“FIPs”) immediately after disapproving individual state implementation plans (“SIPs”).  Because the D.C. Circuit overturned CSAPR on two over-arching issues, the D.C. Circuit must now consider on remand the other issues that it left unaddressed in its first opinion.  On June 26, 2014, the U.S. government filed a motion with the D.C. Circuit to lift the stay of CSAPR.  While the court considers the motion, CAIR remains in place and no immediate action from states or affected sources is required.  Because it is not yet known how the litigation over CSAPR will be resolved, we cannot reasonably predict what requirements, if any, may be imposed under CSAPR in the future, or their timing.  As a result, the full impact of the Supreme Court’s decision on CSAPR cannot be determined until further action by the D.C. Circuit and implementation of CSAPR or an alternative rule promulgated by EPA.  However, the rule will likely, if implemented, require retirement of a number of coal-fired electric generating units, rather than retrofitting the units with the necessary emission control technologies, which closures may reduce the demand for coal.

 

In addition, EPA recently proposed regulations that would impose limits on carbon dioxide emissions from new fossil fuel-fired power plants and, on June 2, 2014, the agency released proposed regulations that would limit carbon emissions from existing power plants.  Under the proposed rule for existing power plants, each state would be required to reduce the carbon intensity of its power sector on a

 

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statewide basis by an amount specified by EPA.  The agency is expected to finalize the proposed rule by June 1, 2015, and states would be required to submit SIPs by June 30, 2016 unless EPA grants an extension.  Although our operations will not be directly affected by these regulations, their ultimate effect on our customer base may lead to a reduction in demand for our coal. As a result, the ultimate impact on our operations remains uncertain.

 

Reference is made to “Item 1. Business – Regulation and Laws – Mine Health and Safety Laws” in our Annual Report on Form 10-K for the year ended December 31, 2013.

 

On April 23, 2014, the Mine Safety and Health Administration (“MSHA”) published its final rule titled “Lowering Miner’s Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors.”  The rule lowers the permissible level of miners’ exposure to respirable coal mine dust, increases sampling requirements, and requires use of certain technology to provide real-time information about dust levels.  The rule also requires immediate corrective action when a single, full-shift sample finds an excessive concentration of dust.  The rule is being challenged in litigation initiated by the National Mining Association and others.  We are continuing to evaluate the potential impact this rule, if upheld, may have on our results of operations and financial position.

 

ITEM 3.                                        QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Commodity Price Risk

 

We have significant long-term coal supply agreements.  Virtually all of the long-term coal supply agreements are subject to price adjustment provisions, which permit an increase or decrease periodically in the contract price to principally reflect changes in specified price indices or items such as taxes, royalties or actual production costs resulting from regulatory changes.

 

We have exposure to price risk for items that are used directly or indirectly in the normal course of coal production such as steel, electricity and other supplies. We manage our risk for these items through strategic sourcing contracts for normal quantities required by our operations.  We do not utilize any commodity price-hedges or other derivatives related to these risks.

 

Credit Risk

 

Most of our sales tonnage is consumed by electric utilities.  Therefore, our credit risk is primarily with domestic electric power generators.  Our policy is to independently evaluate the creditworthiness of each customer prior to entering into transactions and to constantly monitor outstanding accounts receivable against established credit limits. When deemed appropriate by our credit management department, we will take steps to reduce our credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. These steps may include obtaining letters of credit or cash collateral, requiring prepayment for shipments or establishing customer trust accounts held for our benefit in the event of a failure to pay.

 

Exchange Rate Risk

 

Almost all of our transactions are denominated in U.S. dollars, and as a result, we do not have material exposure to currency exchange-rate risks.

 

Interest Rate Risk

 

Borrowings under the Credit Facility are at variable rates and, as a result, we have interest rate exposure.  Historically, our earnings have not been materially affected by changes in interest rates.  We do not utilize any interest rate derivative instruments related to our outstanding debt.  We had $170.0

 

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million in borrowings under the Revolving Credit Facility and $243.8 million outstanding under the Term Loan at June 30, 2014.  A one percentage point increase in the interest rates related to the Revolving Credit Facility and Term Loan would result in an annualized increase in 2014 interest expense of $4.1 million, based on interest rate and borrowing levels at June 30, 2014.  With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a decrease of approximately $7.6 million in the estimated fair value of these borrowings.

 

As of June 30, 2014, the estimated fair value of the ARLP Debt Arrangements was approximately $793.8 million.  The fair values of long-term debt are estimated using discounted cash flow analyses, based upon our current incremental borrowing rates for similar types of borrowing arrangements as of June 30, 2014.  There were no other changes in our quantitative and qualitative disclosures about market risk as set forth in our Annual Report on Form 10-K for the year ended December 31, 2013.

 

ITEM 4.                                        CONTROLS AND PROCEDURES

 

We maintain controls and procedures designed to provide reasonable assurance that information required to be disclosed in the reports we file with the Securities and Exchange Commission (“SEC”) is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.  As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Exchange Act) as of June 30, 2014.  Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective as of June 30, 2014.

 

During the quarterly period ended June 30, 2014, there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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FORWARD-LOOKING STATEMENTS

 

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.”  These statements are based on our beliefs as well as assumptions made by, and information currently available to, us.  When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “may,” “project,” “will,” and similar expressions identify forward-looking statements.  Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are reasonable, but are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements.  Among the factors that could cause actual results to differ from those in the forward-looking statements are:

 

·

changes in competition in coal markets and our ability to respond to such changes;

·

changes in coal prices, which could affect our operating results and cash flows;

·

risks associated with the expansion of our operations and properties;

·

legislation, regulations, and court decisions and interpretations thereof, including those relating to the environment, mining, miner health and safety, and health care;

·

deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or general economic conditions;

·

dependence on significant customer contracts, including renewing customer contracts upon expiration of existing contracts;

·

changing global economic conditions or in industries in which our customers operate;

·

liquidity constraints, including those resulting from any future unavailability of financing;

·

customer bankruptcies, cancellations or breaches to existing contracts, or other failures to perform;

·

customer delays, failure to take coal under contracts or defaults in making payments;

·

adjustments made in price, volume or terms to existing coal supply agreements;

·

fluctuations in coal demand, prices and availability;

·

our productivity levels and margins earned on our coal sales;

·

changes in raw material costs;

·

changes in the availability of skilled labor;

·

our ability to maintain satisfactory relations with our employees;

·

increases in labor costs, adverse changes in work rules, or cash payments or projections associated with post-mine reclamation and workers’ compensation claims;

·

increases in transportation costs and risk of transportation delays or interruptions;

·

operational interruptions due to geologic, permitting, labor, weather-related or other factors;

·

risks associated with major mine-related accidents, such as mine fires, or interruptions;

·

results of litigation, including claims not yet asserted;

·

difficulty maintaining our surety bonds for mine reclamation as well as workers’ compensation and black lung benefits;

·

difficulty in making accurate assumptions and projections regarding pension, black lung benefits and other post-retirement benefit liabilities;

·

the coal industry’s share of electricity generation, including as a result of environmental concerns related to coal mining and combustion and the cost and perceived benefits of other sources of electricity, such as natural gas, nuclear energy and renewable fuels;

·

uncertainties in estimating and replacing our coal reserves;

·

a loss or reduction of benefits from certain tax deductions and credits;

·

difficulty obtaining commercial property insurance, and risks associated with our participation (excluding any applicable deductible) in the commercial insurance property program;

 

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·

difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity investments in companies we do not control; and

·

other factors, including those discussed in “Part II. Item 1A. Risk Factors” and “Part II. Item 1. Legal Proceedings” of this Quarterly Report on Form 10-Q.

 

If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement.  When considering forward-looking statements, you should also keep in mind the risks described in “Risk Factors” below.  These risks could also cause our actual results to differ materially from those contained in any forward-looking statement.  We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

 

You should consider the information above when reading or considering any forward-looking statements contained in:

 

·                 this Quarterly Report on Form 10-Q;

·                 other reports filed by us with the SEC;

·                 our press releases;

·                 our website http://www.arlp.com; and

·                 written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.

 

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PART II

 

OTHER INFORMATION

 

ITEM 1.                                        LEGAL PROCEEDINGS

 

The information in Note 3. Contingencies to the Unaudited Condensed Consolidated Financial Statements included in “Part I. Item 1. Financial Statements (Unaudited)” of this Quarterly Report on Form 10-Q herein is hereby incorporated by reference. See also “Item 3. Legal Proceedings” of our Annual Report on Form 10-K for the year ended December 31, 2013.

 

ITEM 1A.                             RISK FACTORS

 

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in Part I, Item 1A  “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013 which could materially affect our business, financial condition or future results.  The risks described in our Annual Report on Form 10-K and this Quarterly Report on Form 10-Q are not our only risks.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial based on current knowledge and factual circumstances, if such knowledge or facts change, also may materially adversely affect our business, financial condition and/or operating results in the future.

 

ITEM 2.                                        UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

None.

 

ITEM 3.                                        DEFAULTS UPON SENIOR SECURITIES

 

None.

 

ITEM 4.                                        MINE SAFETY DISCLOSURES

 

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Quarterly Report on Form 10-Q.

 

ITEM 5.                                        OTHER INFORMATION

 

None.

 

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ITEM 6.                                        EXHIBITS

 

 

 

 

 

Incorporated by Reference

Exhibit
Number

 

Exhibit Description

 

Form

 

SEC
File No. and
Film No.

 

Exhibit

 

Filing Date

 

Filed
Herewith*

 

 

 

 

 

 

 

 

 

 

 

 

 

3.1

 

Third Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P.

 

8-K

 

000-26823 14922391

 

3.1

 

06/16/2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

31.1

 

Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated August 8, 2014, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

 

 

 

 

 

 

 

GRAPHIC

 

 

 

 

 

 

 

 

 

 

 

 

 

31.2

 

Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated August 8, 2014, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

 

 

 

 

 

 

 

GRAPHIC

 

 

 

 

 

 

 

 

 

 

 

 

 

32.1

 

Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated August 8, 2014, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

 

 

 

 

 

 

GRAPHIC

 

 

 

 

 

 

 

 

 

 

 

 

 

32.2

 

Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated August 8, 2014, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

 

 

 

 

 

 

GRAPHIC

 

 

 

 

 

 

 

 

 

 

 

 

 

95.1

 

Federal Mine Safety and Health Act Information

 

 

 

 

 

 

 

 

 

GRAPHIC

 

 

 

 

 

 

 

 

 

 

 

 

 

101

 

Interactive Data File (Form 10-Q for the quarter ended June 30, 2014 filed in XBRL).

 

 

 

 

 

 

 

 

 

GRAPHIC

 

*                           Or furnished, in the case of Exhibits 32.1 and 32.2.

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, in Tulsa, Oklahoma, on August 8, 2014.

 

 

 

ALLIANCE RESOURCE PARTNERS, L.P.

 

 

 

By:

Alliance Resource Management GP, LLC

 

 

its managing general partner

 

 

 

 

 

/s/ Joseph W. Craft, III

 

 

Joseph W. Craft, III

 

 

President, Chief Executive Officer

 

 

and Director, duly authorized to sign on behalf of the registrant.

 

 

 

 

 

 

 

 

/s/ Brian L. Cantrell

 

 

Brian L. Cantrell

 

 

Senior Vice President and

 

 

Chief Financial Officer

 

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