Alliance Resource Partners (ARLP) 10-Q 2013 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

     Washington, D.C. 20549     

FORM 10-Q

xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2013

OR

oTRANSITION 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 November 7, 2013, 36,963,054 common units are outstanding.

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 September 30, 2013 and December 31, 2012	1
	Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2013 and 2012	2
	Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2013 and 2012	3
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	4
	Notes to Condensed Consolidated Financial Statements	5
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	35
ITEM 4.	Controls and Procedures	36
	Forward-Looking Statements	37
PART II
OTHER INFORMATION
ITEM 1.	Legal Proceedings	39
ITEM 1A.	Risk Factors	39
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
ITEM 3.	Defaults Upon Senior Securities	39
ITEM 4.	Mine Safety Disclosures	39
ITEM 5.	Other Information	39
ITEM 6.	Exhibits	40

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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)

	September 30,			December 31,
ASSETS	2013			2012
CURRENT ASSETS:
Cash and cash equivalents	$	18,871		$	28,283
Trade receivables	169,916			172,724
Other receivables	1,121			1,019
Due from affiliates	740			658
Inventories	69,331			46,660
Advance royalties	11,280			11,492
Prepaid expenses and other assets	3,680			20,476
Total current assets	274,939			281,312
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost	2,576,521			2,361,863
Less accumulated depreciation, depletion and amortization	(990,133		)	(832,293		)
Total property, plant and equipment, net	1,586,388			1,529,570
OTHER ASSETS:
Advance royalties	20,881			23,267
Equity investments in affiliates	124,345			88,513
Due from affiliate	11,150			3,084
Other long-term assets	28,945			30,226
Total other assets	185,321			145,090
TOTAL ASSETS	$	2,046,648		$	1,955,972
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	107,132		$	100,174
Due to affiliates	393			327
Accrued taxes other than income taxes	22,615			19,998
Accrued payroll and related expenses	51,603			38,501
Accrued interest	6,185			1,435
Workers’ compensation and pneumoconiosis benefits	9,478			9,320
Current capital lease obligations	1,214			1,000
Other current liabilities	21,763			19,572
Current maturities, long-term debt (Note 7)	80,500			18,000
Total current liabilities	300,883			208,327
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities	687,500			773,000
Pneumoconiosis benefits	63,921			59,931
Accrued pension benefit	31,202			31,078
Workers’ compensation	70,733			68,786
Asset retirement obligations	76,517			81,644
Long-term capital lease obligations	17,513			18,613
Other liabilities	6,831			9,147
Total long-term liabilities	954,217			1,042,199
Total liabilities	1,255,100			1,250,526
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
Limited Partners - Common Unitholders 36,963,054 and 36,874,949 units outstanding, respectively	1,100,541			1,020,823
General Partners’ deficit	(268,907		)	(273,113		)
Accumulated other comprehensive loss	(40,086		)	(42,264		)
Total Partners’ Capital	791,548			705,446
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	2,046,648		$	1,955,972

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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
SALES AND OPERATING REVENUES:
Coal sales	$	518,447		$	499,003		$	1,594,530		$	1,441,107
Transportation revenues	11,554			5,625			23,459			17,651
Other sales and operating revenues	7,228			6,813			20,866			26,133
Total revenues	537,229			511,441			1,638,855			1,484,891
EXPENSES:
Operating expenses (excluding depreciation, depletion and amortization)	346,045			338,644			1,042,057			946,806
Transportation expenses	11,554			5,625			23,459			17,651
Outside coal purchases	636			4,424			2,028			34,759
General and administrative	14,893			13,598			46,736			43,939
Depreciation, depletion and amortization	66,099			59,781			198,688			154,923
Asset impairment charge	-			19,031			-			19,031
Total operating expenses	439,227			441,103			1,312,968			1,217,109
INCOME FROM OPERATIONS	98,002			70,338			325,887			267,782
Interest expense (net of interest capitalized for the three and nine months ended September 30, 2013 and 2012 of $2,816, $1,701, $8,220 and $6,433, respectively)	(6,168		)	(7,446		)	(19,004		)	(21,626		)
Interest income	252			94			564			238
Equity in loss of affiliates, net	(5,990		)	(2,832		)	(15,556		)	(11,040		)
Other income	372			254			999			2,853
INCOME BEFORE INCOME TAXES	86,468			60,408			292,890			238,207
INCOME TAX BENEFIT	(718		)	(102		)	(1,307		)	(726		)
NET INCOME	$	87,186		$	60,510		$	294,197		$	238,933
GENERAL PARTNERS’ INTEREST IN NET INCOME	$	31,052		$	27,263		$	91,414		$	80,015
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	56,134		$	33,247		$	202,783		$	158,918
BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT (Note 9)	$	1.50		$	0.89		$	5.41		$	4.25
DISTRIBUTIONS PAID PER LIMITED PARTNER UNIT	$	1.1525		$	1.0625		$	3.39		$	3.0775
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING – BASIC AND DILUTED	36,963,054			36,874,949			36,948,531			36,859,018

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 September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
NET INCOME	$	87,186	$	60,510	$	294,197	$	238,933
OTHER COMPREHENSIVE INCOME:
Defined benefit pension plan:
Amortization of actuarial loss (1)	557		458		1,675		1,373
Total defined benefit pension plan adjustments	557		458		1,675		1,373
Pneumoconiosis benefits:
Amortization of actuarial loss (1)	168		194		503		582
Total pneumoconiosis benefits adjustments	168		194		503		582
OTHER COMPREHENSIVE INCOME	725		652		2,178		1,955
TOTAL COMPREHENSIVE INCOME	$	87,911	$	61,162	$	296,375	$	240,888

(1)Amortization of actuarial loss is included in the computation of net periodic benefit cost (see Notes 10 and 12 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)

	Nine Months Ended September 30,
	2013			2012
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	550,385		$	431,628
CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures	(242,653		)	(332,353		)
Changes in accounts payable and accrued liabilities	(354		)	(4,024		)
Proceeds from sale of property, plant and equipment	124			114
Purchases of equity investments in affiliate	(47,500		)	(43,100		)
Payment for acquisition of business	-			(100,000		)
Payments to affiliate for acquisition and development of coal reserves	(21,318		)	(34,601		)
Advances/loans to affiliate	(7,500		)	(2,229		)
Payments from affiliate	-			4,229
Other	-			546
Net cash used in investing activities	(319,201		)	(511,418		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under term loan	-			250,000
Borrowings under revolving credit facilities	211,000			150,000
Payments under revolving credit facilities	(216,000		)	(75,000		)
Payment on term loan	-			(300,000		)
Payment on long-term debt	(18,000		)	(18,000		)
Payments on capital lease obligations	(886		)	(673		)
Payment of debt issuance costs	-			(4,272		)
Net settlement of employee withholding taxes on vesting of Long-Term Incentive Plan	(3,015		)	(3,734		)
Cash contributions by General Partners	114			150
Distributions paid to Partners	(213,809		)	(190,148		)
Net cash used in financing activities	(240,596		)	(191,677		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(9,412		)	(271,467		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	28,283			273,528
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	18,871		$	2,061
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	21,638		$	22,166
NON-CASH INVESTING AND FINANCING ACTIVITY:
Accounts payable for purchase of property, plant and equipment	$	20,618		$	20,955
Market value of common units issued under Long-Term Incentive and Directors Deferred Compensation Plans before minimum statutory tax withholding requirements	$	8,583		$	11,070
Acquisition of business:
Fair value of assets assumed	$	-		$	126,639
Cash paid	-			(100,000		)
Fair value of liabilities assumed	$	-		$	26,639

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 15,544,169 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 September 30, 2013 and December 31, 2012, the results of our operations and comprehensive income for the three and nine months ended September 30, 2013 and 2012 and the cash flows for the nine months ended September 30, 2013 and 2012.  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, 2012.

Use of Estimates

The preparation of the ARLP Partnership’s condensed consolidated financial statements in conformity with generally accepted accounting principles (“GAAP”) 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 Adopted

In February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”).  ASU 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income (“AOCI”) by component.  In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, certain significant amounts reclassified out of AOCI by the respective line items of net income.  ASU 2013-02 does not change the items that must be reported in AOCI.  ASU 2013-02 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2012.  The adoption of ASU 2013-02 did not have a material impact on our condensed consolidated financial statements.

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 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.         ACQUISITIONS

Asset Acquisition

In June 2013, our subsidiary, Alliance Resource Properties, LLC (“Alliance Resource Properties”), acquired the rights to approximately 11.6 million tons of proven and probable medium-sulfur coal reserves, and an additional 5.9 million resource tons, in Grant and Tucker County, West Virginia from Laurel Run Mining Company, a subsidiary of Consol Energy, Inc.  The purchase price of $25.2 million was allocated to owned and leased coal rights and was financed using existing cash on hand.  As a result of the coal reserve purchase, we reclassified certain tons of medium-sulfur, non-reserve coal deposits as reserves, which together with the reserves purchased above, extended the expected life of Mettiki Coal (WV), LLC’s Mountain View mine.

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Green River Collieries, LLC

On April 2, 2012, we acquired substantially all of Green River Collieries, LLC’s (“Green River”) assets related to its coal mining business and operations located in Webster and Hopkins Counties, Kentucky for consideration of $100.0 million.  The transaction included the Onton No. 9 mining complex (“Onton mine”), which included the mine, a dock, tugboat, and a lease for the preparation plant, and an estimated 40.0 million tons of coal reserves in the West Kentucky No. 9 coal seam.   The Green River acquisition was consistent with our general business strategy and complemented our current coal mining operations.

The following unaudited pro forma information for the nine months ended September 30, 2012 for the ARLP Partnership has been prepared for illustrative purposes as if the business combination occurred on January 1, 2011, the year prior to the acquisition date.  The unaudited pro forma results have been prepared based upon Green River’s historical results with respect to the business acquired and estimates of the effects of the transactions that we believe are reasonable and supportable. The results are not necessarily reflective of the consolidated results of operations had the acquisition actually occurred on January 1, 2011, nor are they indicative of future operating results.

	Nine Months Ended
	September 30, 2012
	(in thousands)
Total revenues
As reported	$	1,484,891
Pro forma	$	1,512,234
Net income
As reported	$	238,933
Pro forma	$	240,214

The pro forma net income includes adjustments to depreciation, depletion and amortization to reflect the new basis in property, plant and equipment and intangible assets acquired, elimination of income tax expense, and the elimination of interest expense of Green River as its debt was paid off in conjunction with the acquisition.

Synergies from the acquisition are not reflected in the pro forma results.

5.         ASSET IMPAIRMENT CHARGE

Pontiki Coal, LLC’s (“Pontiki”) mining complex in Martin County, Kentucky was idled from August 29, 2012 to November 25, 2012.  The Mine Safety and Health Administration (“MSHA”) ordered the closure of the coal preparation plant and associated surface facilities at the Pontiki mining complex following the failure on August 23, 2012 of a belt line between two clean coal stacking tubes.  MSHA required a comprehensive structural inspection of all the surface facilities by an independent bridge engineering firm before the surface facilities could be reopened.  Although the Pontiki mining complex resumed operations to fulfill contractual obligations for the delivery of coal in 2013 under existing coal sales agreements, significant uncertainty remained regarding market demand and pricing for coal from Pontiki beyond 2013.  This uncertainty along with the likelihood of future cost increases arising from stringent regulatory oversight placed the long-term viability of Pontiki at significant risk.

As a result of the above events, uncertainty regarding the future operations of the mine and the required additional repair costs, and our assessment of related risks, we concluded that indicators of impairment were present and the carrying value of the asset group representing the Pontiki mining complex (“Pontiki Assets”) was not fully recoverable.  We estimated the fair value of the Pontiki Assets

7

and determined it was exceeded by the carrying value and accordingly, we recorded an asset impairment charge of $19.0 million in our Central Appalachian segment during the quarter ended September 30, 2012 to reduce the carrying value of the Pontiki Assets to their estimated fair value of $16.1 million.  The fair value of the Pontiki Assets was determined using the market and cost valuation techniques and represents a Level 3 fair value measurement.  The fair value analysis was based on the marketability of coal properties in the current market environment, discounted projected future cash flows, and estimated fair value of assets that could be sold or used at other operations.  As these estimates incorporate certain assumptions, including replacement cost of equipment and marketability of coal reserves in the Central Appalachian region, and it is possible that the estimates may change in the future resulting in the need to adjust our determination of fair value.  The asset impairment established a new cost basis on which depreciation, depletion and amortization is calculated for the Pontiki Assets.

As noted above, although the Pontiki mining complex resumed operations, significant uncertainty remained regarding market demand and pricing for coal from Pontiki beyond 2013.  On September 27, 2013, we issued Worker Adjustment and Retraining Notification (WARN) Act notices to all employees at Pontiki’s mining complex.  We plan to continue operations at the Pontiki mining complex until late November 2013 to fulfill commitments under existing sales contracts at which time the mine is expected to cease production.  No additional impairment was required related to the expected closure of the mine as the depreciable lives of the Pontiki Assets were adjusted in 2012 and throughout 2013 as management evaluated the future operations at Pontiki.

6.         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 September 30, 2013 and December 31, 2012, the estimated fair value of our long-term debt, including current maturities, was approximately $787.3 million and $834.3 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 7). 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.

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7.         LONG-TERM DEBT

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

	September 30, 2013			December 31, 2012
Revolving credit facility	$	100,000		$	155,000
$50 million facility	50,000			-
Senior notes	18,000			36,000
Series A senior notes	205,000			205,000
Series B senior notes	145,000			145,000
Term loan	250,000			250,000
	768,000			791,000
Less current maturities	(80,500		)	(18,000		)
Total long-term debt	$	687,500		$	773,000

On September 11, 2013, our Intermediate Partnership entered into a credit agreement for a $50.0 million revolving credit facility (“Facility”) to be used, as appropriate, for short-term working capital requirements.  The counterparty to the Facility is KC-LendCo, LLC, which is controlled by an officer of ARH via his role as independent trustee of irrevocable trusts established by our President and Chief Executive Officer.  Borrowings under the Facility bear interest at the London Interbank Offered Rate (“LIBOR”) plus 0.80%, with interest payable quarterly.  At September 30, 2013, the LIBOR with applicable margin was 0.98% on borrowings outstanding.  The Facility is included in the current maturities, long-term debt line item on our condensed consolidated balance sheet.  The lender and the Intermediate Partnership have the option to terminate the Facility at any time and the Facility was terminated on October 29, 2013, with all amounts outstanding, plus interest, paid in full.

Our Intermediate Partnership also 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 $250.0 million 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. 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, the incurrence of additional indebtedness and liens, the sale of assets, the making of investments, the entry into mergers and consolidations and the entry into 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 1.12 to 1.0 and 19.4 to 1.0, respectively, for the trailing twelve months ended September 30, 2013.  We were in compliance with the covenants of the ARLP Debt Arrangements as of September 30, 2013.

At September 30, 2013, we had borrowings of $150.0 million and $23.5 million of letters of credit outstanding with $576.5 million available for borrowing under the Revolving Credit Facility and the Facility.  We utilize the Revolving Credit Facility, as appropriate, for working capital requirements, anticipated 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.

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8.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 backstop equipment financing facility.  Our initial investment funding to White Oak at the Transaction Date, consummated utilizing existing cash on hand, was $69.5 million and we funded an additional $197.7 million to White Oak between the Transaction Date and September 30, 2013.  We expect to fund a total of approximately $300.5 million from the Transaction Date through approximately the next 1.5 years, which includes the funding made to White Oak through September 30, 2013 discussed above.  We are also committed to invest up to an additional $125.0 million in Series A Units to the extent required for development or operation of the White Oak Mine No. 1 mine, which is subject to certain rights and obligations of other White Oak owners to participate in such investment.  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.  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.   The following information discusses each component of these transactions in further detail.

Hamilton County, Illinois Reserve Acquisition

On the Transaction Date, our subsidiary, 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”).  Hamilton County is adjacent to White County, Illinois, where our White County Coal, LLC 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.  During the nine months ended September 30, 2013, WOR Properties acquired from White Oak for $21.3 million cash paid at closing, an additional 75.4 million tons of reserves, of which 38.8 million tons are currently being developed for future mining by White Oak.  WOR Properties has a remaining commitment of $33.2 million for additional coal reserve purchases and development funding.

Equity Investment – Series A Units

Concurrent with the Reserve Acquisition, our subsidiary, Alliance WOR Processing, LLC (“WOR Processing”), made an equity investment of $35.7 million in White Oak to purchase Series A Units representing ownership in White Oak.  WOR Processing purchased $66.8 million of additional Series A Units between the Transaction Date and December 31, 2012 and $47.5 million of additional Series A Units during the nine months ended September 30, 2013, fulfilling WOR Processing’s minimum equity investment commitment.  Based on currently anticipated equity contributions by other White Oak owners, we do not expect to make further equity investments in White Oak in 2013.

WOR Processing’s ownership and member’s voting interest in White Oak at September 30, 2013 were 20.0% based upon currently outstanding voting units.  The remainder of the equity ownership in White Oak, represented by Series 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

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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 September 30, 2013, WOR Processing had invested $150.0 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 nine months ended September 30, 2013 and 2012, we were allocated losses of $6.2 million, $3.0 million, $16.3 million and $11.6 million, respectively.

Services Agreement

Simultaneous with the closing of the Reserve Acquisition, WOR Processing entered into a Coal Handling and Preparation Agreement (“Services 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.  During the quarter ended September 30, 2013, WOR Processing began processing and loading coal through the facilities and earned throughput fees of $0.6 million from White Oak.

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 has borrowed the entire amount available under the Construction Loan as of September 30, 2013.

9.         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 managing general partner is entitled to receive 15% of the amount we distribute in excess of $0.275 per unit, 25% of the amount we distribute in excess of $0.3125 per unit, and 50% of the amount we distribute in excess of $0.375 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, our 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.

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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 nine months ended September 30, 2013 and 2012 (in thousands, except per unit data):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net income	$	87,186		$	60,510		$	294,197		$	238,933
Adjustments:
Managing general partner’s priority distributions	(29,906		)	(26,584		)	(87,275		)	(76,771		)
General partners’ 2% equity ownership	(1,146		)	(679		)	(4,139		)	(3,244		)
Limited partners’ interest in net income	56,134			33,247			202,783			158,918
Less:
Distributions to participating securities	(597		)	(531		)	(1,749		)	(1,549		)
Undistributed earnings attributable to participating securities	(167		)	-			(1,012		)	(541		)
Net income available to limited partners	$	55,370		$	32,716		$	200,022		$	156,828
Weighted average limited partner units outstanding – basic and diluted	36,963			36,875			36,949			36,859
Basic and diluted net income per limited partner unit (1)	$	1.50		$	0.89		$	5.41		$	4.25

(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 nine months ended September 30, 2013 and 2012, LTIP, SERP and Deferred Compensation Plan units of 355,259, 323,146, 328,314 and 338,231 respectively, were considered anti-dilutive under the treasury stock method.

10.       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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Beginning balance	$	80,630		$	81,195		$	77,046		$	73,201
Accruals increase	452			4,035			8,399			16,249
Payments	(2,553		)	(2,395		)	(8,156		)	(7,984		)
Interest accretion	621			685			1,861			2,054
Ending balance	$	79,150		$	83,520		$	79,150		$	83,520

Lower accrual increases in 2013 compared to 2012 was primarily attributable to favorable reserve adjustments for claims incurred in prior years.

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.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Service cost	$	953	$	960	$	2,858	$	2,795
Interest cost	563		598		1,690		1,773
Amortization of net loss (1)	168		194		503		582
Net periodic benefit cost	$	1,684	$	1,752	$	5,051	$	5,150

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

11.       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 23, 2013, the Compensation Committee determined that the vesting requirements for the 2010 grants of 130,102 restricted units (which is net of 8,028 forfeitures) had been satisfied as of January 1, 2013.  As a result of this vesting, on February 15, 2013, we issued 82,400 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 23, 2013, the Compensation Committee authorized additional grants of up to 156,575 restricted units, of which 146,725 were granted during the nine months ended September 30, 2013 and will vest on January 1, 2016, subject to satisfaction of certain financial tests.  The fair value of these 2013 grants is equal to the intrinsic value at the date of grant, which was $63.02 per unit.  LTIP expense was $1.8 million and $1.6 million for the three months ended September 30, 2013 and 2012, respectively, and $5.4 million and $4.7 million for the nine months ended September 30, 2013 and 2012, respectively.  After consideration of the January 1, 2013 vesting and subsequent issuance of 82,400 common units, 2.1 million units remain available under the LTIP for issuance in the future, assuming all grants issued in 2011, 2012 and 2013 currently outstanding are settled with common units, without reduction for tax withholding, and no future forfeitures occur.

As of September 30, 2013, there was $10.7 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 1.4 years.  As of September 30, 2013, the intrinsic value of the non-vested LTIP grants was $25.8 million.  As of September 30, 2013, 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.

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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 nine months ended September 30, 2013 and 2012, SERP and Deferred Compensation Plan participant notional account balances were credited with a total of 10,835 and 7,168 phantom units, respectively, and the fair value of these phantom units was $68.32 per unit and $64.77 per unit, respectively, on a weighted-average basis.  Total SERP and Deferred Compensation Plan expense was approximately $0.3 million and $0.2 million for the three months ended September 30, 2013 and 2012, respectively, and $0.9 and $0.6 million for the nine months ended September 30, 2013 and 2012, respectively.

As of September 30, 2013, there were 167,626 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 $12.4 million.  As of September 30, 2013, the total obligation associated with the SERP and Deferred Compensation Plan was $11.1 million and is included in the partners’ capital-limited partners line item in our condensed consolidated balance sheets.

12.       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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Service cost	$	674		$	726		$	2,108		$	2,179
Interest cost	929			818			2,710			2,454
Expected return on plan assets	(930		)	(956		)	(3,094		)	(2,868		)
Amortization of net loss (1)	557			458			1,675			1,373
Net periodic benefit cost	$	1,230		$	1,046		$	3,399		$	3,138

(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, 2012 that we expected to contribute $2.4 million to the Pension Plan in 2013.  During the nine months ended

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September 30, 2013, we made contribution payments of $1.6 million for the 2013 plan year.  On October 15, 2013, we made a contribution payment of $0.8 million for the 2013 plan year, bringing the total contributions to the Pension Plan in 2013 for the 2013 plan year to $2.4 million as expected.

13.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 five reportable segments: the Illinois Basin, Central Appalachia, Northern Appalachia, White Oak and Other and Corporate.  The first three reportable segments correspond to the three major coal producing regions in the eastern U.S.  Similar economic characteristics for our operating segments within each of these three reportable segments include coal quality, coal seam height, 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 project, 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 is currently underway.  For information regarding the acquisition of the Onton mine, which was added to the Illinois Basin segment in April 2012, please see Note 4.

The Central Appalachian reportable segment is comprised of two operating segments, the MC Mining, LLC and Pontiki mining complexes.

The Northern Appalachian reportable segment is comprised of multiple operating segments, including the Mettiki mining complex, the Tunnel Ridge, LLC (“Tunnel Ridge”) 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.  In May 2012, longwall production began at the Tunnel Ridge mine.  We are in the process of permitting the Penn Ridge property for future mine development.

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 8).

Other and Corporate 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 and certain activities of Alliance Resource Properties.

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Reportable segment results as of and for the three and nine months ended September 30, 2013 and 2012 are presented below.

	Illinois Basin		Central Appalachia		Northern Appalachia		White Oak		Other and Corporate		Elimination (1)		Consolidated
	(in thousands)
Reportable segment results for the three months ended September 30, 2013 were as follows:
Total revenues (2)	$	405,597	$	40,135	$	84,975	$	566	$	8,702	$	(2,746)	$	537,229
Segment Adjusted EBITDA Expense (3)	239,962		30,348		69,415		546		8,784		(2,746)		346,309
Segment Adjusted EBITDA (4)(5)	156,790		9,775		12,864		(6,190)		137		-		173,376
Capital expenditures (7)	58,569		2,459		12,284		6,632		2,137		-		82,081
Reportable segment results for the three months ended September 30, 2012 were as follows:
Total revenues (2)	$	365,119	$	41,790	$	100,142	$	-	$	8,518	$	(4,128)	$	511,441
Segment Adjusted EBITDA Expense (3)	221,731		35,563		81,761		174		7,713		(4,128)		342,814
Segment Adjusted EBITDA (4)(5)	140,329		6,228		15,813		(3,188)		988		-		160,170
Capital expenditures (7)	51,541		9,395		21,422		10,468		1,197		-		94,023
Reportable segment results as of and for the nine months ended September 30, 2013 were as follows:
Total revenues (2)	$	1,210,806	$	126,701	$	284,303	$	566	$	26,696	$	(10,217)	$	1,638,855
Segment Adjusted EBITDA Expense (3)	707,810		96,786		219,356		1,074		28,277		(10,217)		1,043,086
Segment Adjusted EBITDA (4)(5)	488,634		29,691		56,074		(16,777)		(868)		-		556,754
Total assets (6)	1,064,268		84,162		539,194		306,002		53,887		(865)		2,046,648
Capital expenditures (7)	163,595		8,758		51,154		35,502		4,962		-		263,971
Reportable segment results as of and for the nine months ended September 30, 2012 were as follows:
Total revenues (2)	$	1,082,057	$	122,989	$	247,104	$	-	$	46,674	$	(13,933)	$	1,484,891
Segment Adjusted EBITDA Expense (3)	652,231		96,920		202,449		(1,517)		42,562		(13,933)		978,712
Segment Adjusted EBITDA (4)(5)	419,955		25,618		37,326		(10,072)		4,661		-		477,488
Total assets (6)	1,030,860		81,867		521,156		198,631		34,580		(825)		1,866,269
Capital expenditures (7)	173,656		25,143		82,320		74,712		11,123		-		366,954

(1)The elimination column represents the elimination of intercompany transactions and is primarily comprised of sales from the Matrix Group to our mining operations.

(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 and brokerage sales.

(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				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Segment Adjusted EBITDA Expense	$	346,309	$	342,814	$	1,043,086	$	978,712
Outside coal purchases	(636)		(4,424)		(2,028)		(34,759)
Other income	372		254		999		2,853
Operating expenses (excluding depreciation, depletion and amortization)	$	346,045	$	338,644	$	1,042,057	$	946,806

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(4)Segment Adjusted EBITDA is defined as net income before net interest expense, income taxes, depreciation, depletion and amortization, general and administrative expenses and asset impairment charge.  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				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Consolidated Segment Adjusted EBITDA	$	173,376	$	160,170	$	556,754	$	477,488
General and administrative	(14,893)		(13,598)		(46,736)		(43,939)
Depreciation, depletion and amortization	(66,099)		(59,781)		(198,688)		(154,923)
Asset impairment charge	-		(19,031)		-		(19,031)
Interest expense, net	(5,916)		(7,352)		(18,440)		(21,388)
Income tax benefit	718		102		1,307		726
Net income	$	87,186	$	60,510	$	294,197	$	238,933

(5)Includes equity in income (loss) of affiliates for the three and nine months ended September 30, 2013 of $(6.2) million and $(16.3) million, respectively, included in the White Oak segment and $0.2 million and $0.7 million, respectively, included in the Other and Corporate segment.  Includes equity in income (loss) of affiliates for the three and nine months ended September 30, 2012 of $(3.0) million and $(11.6) million, respectively, included in the White Oak segment and $0.1 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 $122.7 million and $1.6 million, respectively, at September 30, 2013 and $72.7 million and $1.6 million, respectively, at September 30, 2012.

(7)Capital expenditures shown above include funding to White Oak of $2.5 million and $21.3 million, respectively, for the three and nine months ended September 30, 2013, and $34.6 million for the three and nine months ended September 30, 2012, for the acquisition and development of coal reserves in our condensed consolidated statements of cash flow.

14.SUBSEQUENT EVENTS

On October 28, 2013, we declared a quarterly distribution for the quarter ended September 30, 2013, of $1.175 per unit, on all common units outstanding, totaling approximately $74.2 million (which includes our managing general partner’s incentive distributions), payable on November 14, 2013 to all unitholders of record as of November 7, 2013.

Other than those events described above and in Note 7, there were no other subsequent events.

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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 eleven underground mining complexes in Illinois, Indiana, Kentucky, Maryland and West Virginia, including the new Tunnel Ridge, LLC (“Tunnel Ridge”) longwall mine in West Virginia and the Onton No. 9 mining complex (“Onton mine”) in west Kentucky acquired on April 2, 2012.  We are constructing a new mine in southern Indiana and operate a coal loading terminal on the Ohio River at Mt. Vernon, Indiana.  Also, we own a preferred equity interest 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 five reportable segments: Illinois Basin, Central Appalachia, Northern Appalachia White Oak and Other and Corporate.  The first three reportable segments correspond to the three major coal producing regions in the eastern U.S.  Factors similarly affecting financial performance of our operating segments within each of these three reportable segments include coal quality, coal seam height, 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, LLC’s mining complex, which includes the Gibson North mine and Gibson South project, Hopkins County Coal, LLC’s Elk Creek mining complex, 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 (“Alliance Resource Properties”), ARP

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Sebree, LLC and ARP Sebree South, LLC.  The development of the Gibson South mine is currently underway and we are in the process of permitting the Sebree property for future mine development.  For information regarding the acquisition of the Onton mine, which was added to the Illinois Basin segment in April 2012, please read “Item 1. Financial Statements (Unaudited) – Note 4. Acquisitions” of this Quarterly Report on Form 10-Q.

·Central Appalachian reportable segment is comprised of two operating segments, the Pontiki Coal, LLC (“Pontiki”) and MC Mining, LLC (“MC Mining”) mining complexes.  Please read “Item 1. Financial Statements (Unaudited) – Note 5. Asset Impairment Charge” of this Quarterly Report on Form 10-Q for additional information regarding this asset impairment.

·Northern Appalachian reportable segment is comprised of multiple operating segments, including the Mettiki mining complex, the Tunnel Ridge 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.  In May 2012, longwall production began at the Tunnel Ridge mine.  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 Processing includes both the surface operations at White Oak and the equity investment in White Oak.  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 certain funding to White Oak for development of these reserves.  The White Oak reportable segment also includes two loans to White Oak from our Intermediate Partnership, one for the acquisition of mining equipment (which was paid off and terminated in June 2012) and another to construct certain surface facilities. For more information on White Oak, please read “Item 1. Financial Statements (Unaudited) – Note 8. White Oak Transactions” of this Quarterly Report on Form 10-Q.

·Other and Corporate reportable segment includes marketing and administrative expenses, Alliance Service, Inc. (“ASI”) and its subsidiary, Matrix Design Group, LLC (“Matrix Design”), Alliance Design Group, LLC (collectively, Matrix Design and Alliance Design Group, LLC 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 (“MAC”) and certain activities of Alliance Resource Properties.

Pontiki Mine

Pontiki’s mining complex in Martin County, Kentucky was idled from August 29, 2012 to November 25, 2012.  The Mine Safety and Health Administration (“MSHA”) ordered the closure of the coal preparation plant and associated surface facilities at the Pontiki mining complex following the failure on August 23, 2012 of a belt line between two clean coal stacking tubes.  MSHA required a comprehensive structural inspection of all the surface facilities by an independent bridge engineering firm before the surface facilities could be reopened.

As a result of the above events, uncertainty regarding the future operations of the mine and the required additional repair costs, and our assessment of related risks, we concluded that indicators of impairment were present and the carrying value of the asset group representing the Pontiki mining complex (“Pontiki Assets”) was not fully recoverable as of September 30, 2012.  We estimated the fair value of the Pontiki Assets and determined it exceeded the carrying amount and accordingly, we recorded an asset impairment charge of $19.0 million for the three months ended September 30, 2012 (“2012 Quarter”).

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Although the Pontiki mining complex resumed operations, significant uncertainty remained regarding market demand and pricing for coal from Pontiki beyond 2013.  On September 27, 2013, we issued Worker Adjustment and Retraining Notification (WARN) Act notices to all employees at Pontiki’s mining complex.  We plan to continue operations at the Pontiki mining complex until late November 2013 to fulfill commitments under existing sales contracts at which time the mine is expected to cease production.  Please also read “Item 1. Financial Statements (Unaudited) – Note 5. Asset Impairment Charge” of this Quarterly Report on Form 10-Q for additional information regarding this asset impairment.

Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012

We reported net income of $87.2 million for the three months ended September 30, 2013 (“2013 Quarter”) compared to $60.5 million for the 2012 Quarter. The increase of $26.7 million was principally due to increased coal sales and production volumes, which rose to 9.5 million tons sold and 9.7 million tons produced in the 2013 Quarter compared to 8.9 million tons sold and 9.0 million tons produced in the 2012 Quarter. The 2012 Quarter was also negatively impacted by the temporary idling of our Pontiki mining complex and the related non-cash impairment charge of $19.0 million. The increases in tons sold and tons produced resulted from increased volumes at the Tunnel Ridge, River View, Gibson North and Dotiki mines. Increased coal sales and production volumes led to increased operating expenses, which particularly impacted labor and related benefits expense, materials and supplies expense, maintenance cost and sales related expense. The increases in operating expenses were offset partially by lower outside coal purchases in the 2013 Quarter.

	Three Months Ended September 30,
	2013	2012	2013	2012
	(in thousands)		(per ton sold)
Tons sold	9,504	8,910	N/A	N/A
Tons produced	9,682	9,000	N/A	N/A
Coal sales	$518,447	$499,003	$54.55	$56.00
Operating expenses and outside coal purchases	$346,681	$343,068	$36.48	$38.50

Coal sales.  Coal sales for the 2013 Quarter increased 3.9% to $518.4 million from $499.0 million for the 2012 Quarter.  The increase of $19.4 million in coal sales reflected the benefit of increased tons sold (contributing $33.2 million in additional coal sales) offset partially by lower average coal sales prices (reducing coal sales by $13.8 million).  Average coal sales prices in the 2013 Quarter decreased to $54.55 compared to $56.00 per ton in the 2012 Quarter, primarily as a result of the lack of coal sales into the metallurgical export markets.

Operating expenses and outside coal purchases.  Operating expenses and outside coal purchases combined increased slightly to $346.7 million for the 2013 Quarter from $343.1 million for the 2012 Quarter, primarily due to increased coal sales and production volumes partially offset by lower outside coal purchases.  On a per ton basis, operating expenses and outside coal purchases decreased 5.2% to $36.48 per ton sold.  In addition to the impact of increased production and sales volumes, operating expenses were impacted by various other factors, the most significant of which are discussed below:

·Labor and benefit expenses per ton produced, excluding workers’ compensation, decreased 1.9% to $11.92 per ton in the 2013 Quarter from $12.15 per ton in the 2012 Quarter.  This decrease of $0.23 per ton was primarily attributable to lower labor costs per ton resulting from increased production at our Tunnel Ridge and Dotiki mines and improved coal recoveries from our River View and Gibson North mines, partially offset by reduced production at our Onton mine and higher employee benefits expense at our Mettiki mine.  The Onton mine temporarily ceased production in July 2013 due to unfavorable geological conditions and resumed full production in mid-August 2013;

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·Workers’ compensation expenses per ton produced decreased to $0.41 per ton in the 2013 Quarter from $0.80 per ton in the 2012 Quarter.  The decrease of $0.39 per ton produced resulted primarily from increased production discussed above and favorable claim trends;

·Contract mining expense decreased $2.4 million for the 2013 Quarter compared to the 2012 Quarter.  The decrease primarily reflects lower production from a third-party mining operation in our Northern Appalachian region due to reduced metallurgical coal export market opportunities;

·Production taxes and royalties expenses (which were incurred as a percentage of coal sales prices and volumes) decreased $0.20 per produced ton sold in the 2013 Quarter compared to the 2012 Quarter primarily as a result of lower average coal sales prices for Northern Appalachian due to reduced sales of metallurgical coal;

·Outside coal purchases decreased to $0.6 million for the 2013 Quarter from $4.4 million in the 2012 Quarter.  The decrease of $3.8 million was primarily attributable to reduced volumes of coal purchased for sale into the metallurgical export markets.  Coal purchase costs per ton are typically higher than our production costs per ton, thus significantly lower volumes of coal purchases in the 2013 Quarter reduced our overall total expenses per ton compared to the 2012 Quarter; and

·Operating expenses per ton also decreased in the 2013 Quarter due to lower cost per ton beginning coal inventories in the 2013 Quarter.

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

·Material and supplies expenses per ton produced increased slightly to $11.96 per ton in the 2013 Quarter from $11.92 per ton in the 2012 Quarter.  The increase of $0.04 per ton produced resulted primarily from increases in cost for certain products and services, primarily roof support (increase of $0.31 per ton) and certain safety-related materials and supplies (increase of $0.30 per ton) partially offset by a decrease in outside expenses (decrease of $0.18 per ton), power and fuel used in the mining process (decrease of $0.10 per ton) and contract labor used in the mining process (decrease of $0.07 per ton).  Higher safety-related materials and supplies primarily resulted from activity at our Onton mine during the temporary halt of production operations discussed above; and

·Operating expenses for the 2013 Quarter included $3.8 million related to the retirement of certain assets also resulting from the Onton mine’s previously mentioned adverse geological conditions.

Depreciation, depletion and amortization.  Depreciation, depletion and amortization expense increased to $66.1 million for the 2013 Quarter from $59.8 million for the 2012 Quarter.  The increase of $6.3 million was primarily attributable to increased production volumes mentioned above, as well as capital expenditures related to production expansion and infrastructure investments at various operations.

General and administrative.  General and administrative expenses for the 2013 Quarter increased to $14.9 million compared to $13.6 million in the 2012 Quarter.  The increase of $1.3 million was primarily due to increases in incentive compensation expense.

Asset impairment charge.  In the 2012 Quarter, we recorded an asset impairment charge of $19.0 million associated with the long-lived assets at our Pontiki mining complex as discussed in more detail above and in “Item 1. Financial Statements (Unaudited) – Note 5. Asset Impairment Charge.”

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Interest expense.  Interest expense, net of capitalized interest, decreased to $6.2 million for the 2013 Quarter from $7.4 million for the 2012 Quarter.  The decrease of $1.2 million was principally attributable to increased capitalized interest on our equity investment in White Oak, as well as reduced interest expense resulting from our August 2013 principal repayment of $18.0 million on our original senior notes issued in 1999.  This decrease was partially offset by increased borrowings under our revolving credit facilities during the 2013 Quarter.  The revolving credit facilities are discussed in more detail 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 2013 Quarter, equity in loss of affiliates was $6.0 million compared to $2.8 million for the 2012 Quarter, which was primarily attributable to losses allocated to us from our equity investment in White Oak.

Transportation revenues and expenses.  Transportation revenues and expenses were $11.6 million and $5.6 million for the 2013 and 2012 Quarters, respectively.  The increase of $6.0 million was primarily attributable to an increase in average transportation rates in the 2013 Quarter related to new export sales from our Warrior mine.  The cost of transportation services are passed through to our customers.  Consequently, we do not realize any gain or loss on transportation revenues.

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Segment Adjusted EBITDA.  Our 2013 Quarter Segment Adjusted EBITDA increased $13.2 million, or 8.2%, to $173.4 million from the 2012 Quarter Segment Adjusted EBITDA of $160.2 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 September 30,
	2013		2012		Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	156,790	$	140,329	$	16,461	11.7	%
Central Appalachia	9,775		6,228		3,547		57.0	%
Northern Appalachia	12,864		15,813		(2,949)		(18.6	)%
White Oak	(6,190)		(3,188)		(3,002)		(94.2	)%
Other and Corporate	137		988		(851)		(86.1	)%
Elimination	-		-		-		-
Total Segment Adjusted EBITDA (2)	$	173,376	$	160,170	$	13,206	8.2	%
Tons sold
Illinois Basin	7,598		6,919		679		9.8	%
Central Appalachia	490		523		(33)		(6.3	)%
Northern Appalachia	1,405		1,468		(63)		(4.3	)%
White Oak	-		-		-		-
Other and Corporate	11		-		11		(1	)
Elimination	-		-		-		-
Total tons sold	9,504		8,910		594		6.7	%
Coal sales
Illinois Basin	$	396,056	$	361,206	$	34,850	9.6	%
Central Appalachia	39,959		41,790		(1,831)		(4.4	)%
Northern Appalachia	81,440		95,988		(14,548)		(15.2	)%
White Oak	-		-		-		-
Other and Corporate	992		19		973		(1	)
Elimination	-		-		-		-
Total coal sales	$	518,447	$	499,003	$	19,444	3.9	%
Other sales and operating revenues
Illinois Basin	$	696	$	853	$	(157)	(18.4	)%
Central Appalachia	165		-		165		(1	)
Northern Appalachia	839		1,587		(748)		(47.1	)%
White Oak	566		-		566		(1	)
Other and Corporate	7,708		8,501		(793)		(9.3	)%
Elimination	(2,746)		(4,128)		1,382		33.5	%
Total other sales and operating revenues	$	7,228	$	6,813	$	415	6.1	%
Segment Adjusted EBITDA Expense
Illinois Basin	$	239,962	$	221,731	$	18,231	8.2	%
Central Appalachia	30,348		35,563		(5,215)		(14.7	)%
Northern Appalachia	69,415		81,761		(12,346)		(15.1	)%
White Oak	546		174		372		(1	)
Other and Corporate	8,784		7,713		1,071		13.9	%
Elimination	(2,746)		(4,128)		1,382		33.5	%
Total Segment Adjusted EBITDA Expense (3)	$	346,309	$	342,814	$	3,495	1.0	%

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

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(2)Segment Adjusted EBITDA (a non-GAAP financial measure) is defined as net income before net interest expense, income taxes, depreciation, depletion and amortization, general and administrative expenses and asset impairment charge.  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:

·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 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
	September 30,
	2013		2012
Segment Adjusted EBITDA	$	173,376	$	160,170
General and administrative	(14,893)		(13,598)
Depreciation, depletion and amortization	(66,099)		(59,781)
Asset impairment charge	-		(19,031)
Interest expense, net	(5,916)		(7,352)
Income tax benefit	718		102
Net income	$	87,186	$	60,510

(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 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
	September 30,
	2013		2012
Segment Adjusted EBITDA Expense	$	346,309	$	342,814
Outside coal purchases	(636)		(4,424)
Other income	372		254
Operating expense (excluding depreciation, depletion and amortization)	$	346,045	$	338,644

Illinois Basin – Segment Adjusted EBITDA increased 11.7% to $156.8 million in the 2013 Quarter from $140.3 million in the 2012 Quarter.  This increase of $16.5 million was primarily attributable to higher tons sold which increased 9.8% to 7.6 million tons in the 2013 Quarter.  Coal sales increased 9.6% to $396.1 million in the 2013 Quarter compared to $361.2 million in the 2012 Quarter. The sales increase of $34.9 million primarily reflects increased tons sold and produced from our River View, Gibson North and Dotiki mines, offset partially by the temporary halt of production operations at the Onton mine due to adverse geological conditions during the 2013 Quarter.  Total Segment Adjusted EBITDA Expense for the 2013 Quarter increased 8.2% to $240.0 million from $221.7 million in the 2012 Quarter primarily due to increased sales and production volumes noted above and the impact of the temporary halt of production at the Onton mine discussed above.  Although Segment Adjusted EBITDA Expense increased, Segment Adjusted EBITDA Expense per ton decreased $0.46 per ton sold to $31.58 from $32.04 per ton sold, primarily as a result of increased coal production discussed above as well as certain cost per ton decreases described above under “–Operating expenses and outside coal purchases.”

Central Appalachia – Segment Adjusted EBITDA increased 57.0% to $9.8 million for the 2013 Quarter compared to $6.2 million in the 2012 Quarter.  The increase of $3.6 million was primarily attributable to higher coal sales prices, increased production and lower inventory cost in the 2013 Quarter compared to the 2012 Quarter.  This increase was offset partially by a decrease in coal sales volumes, primarily as a result of timing differences in customer shipments during the 2013 Quarter compared to the 2012 Quarter.  Segment Adjusted EBITDA Expense for the 2013 Quarter decreased 14.7% to $30.3 million from $35.6 million in the 2012 Quarter and decreased $6.15 per ton sold to $61.89 compared to $68.04 per ton in the 2012 Quarter, primarily as a result of increased production, lower inventory costs and repair costs in the 2013 Quarter.  Repair costs and production in the 2012 Quarter were negatively impacted by previously mentioned regulatory actions at our Pontiki mine.  For additional detail related to the Pontiki mining complex read “Item 1. Financial Statements (Unaudited) – Note 5. Asset Impairment Charge.”

Northern Appalachia – Segment Adjusted EBITDA decreased to $12.9 million for the 2013 Quarter as compared to $15.8 million in the 2012 Quarter. This decrease of $2.9 million was primarily attributable to the lack of coal sales into the metallurgical export markets, resulting in a lower average sales price of $57.97 per ton sold for the 2013 Quarter compared to $65.43 per ton sold for the 2012 Quarter, as well as lower tons sold, which decreased 4.3% compared to the 2012 Quarter.  The decrease in tons sold was due to the timing of shipments from Mettiki in the 2013 Quarter compared to the 2012 Quarter, offset in part by increased coal sales from the continued ramp-up of longwall production at the Tunnel Ridge mine.  Segment Adjusted EBITDA Expense for the 2013 Quarter decreased 15.1% to $69.4 million from $81.8 million in the 2012 Quarter and decreased $6.32 per ton sold to $49.41 from $55.73 per ton sold, primarily as a result of improved productivity from our Tunnel Ridge mine long-wall operations which began in May 2012, reduced outside coal purchases, contract mining expenses and coal processing expenses at our Mettiki mine all resulting from the lack of coal sales into the metallurgical export markets, partially offset by higher employee benefit costs at Mettiki.

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White Oak – Segment Adjusted EBITDA was $(6.2) million and $(3.2) million, respectively, in the 2013 and 2012 Quarters primarily attributable to losses allocated to us due to our equity interest in White Oak.  For more information on White Oak, please read “Item 1. Financial Statements (Unaudited) – Note 8. White Oak Transactions” of this Quarterly Report on Form 10-Q.

Other and Corporate – Segment Adjusted EBITDA decreased $0.9 million in the 2013 Quarter from the 2012 Quarter.  This decrease was primarily attributable to lower sales of Matrix safety equipment.  Segment Adjusted EBITDA Expense increased 13.9% to $8.8 million for the 2013 Quarter compared to $7.7 million for the 2012 Quarter, primarily due to higher outside coal purchases and increases in component expenses by the Matrix group.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

We reported net income of $294.2 million for the nine months ended September 30, 2013 (“2013 Period”) compared to $238.9 million for the nine months ended September 30, 2012 (“2012 Period”). This increase of $55.3 million was principally due to record coal sales and production volumes. We had tons sold of 29.0 million tons and tons produced of 29.6 million tons in the 2013 Period compared to 25.4 million tons sold and 25.7 million tons produced in the 2012 Period. The 2012 Period was also negatively impacted by the temporary idling of our Pontiki mining complex and the related non-cash impairment charge of $19.0 million. The increase in tons sold and produced resulted from increased production at the Tunnel Ridge mine, which began longwall production in May 2012, increased tons produced and sold from our River View and Gibson North mines and the addition of the Onton mine in April 2012. Higher operating expenses during the 2013 Period resulted primarily from the record coal sales and production volumes, which particularly impacted labor and related benefits expense, materials and supplies expense, maintenance costs and sales-related expenses. These increases in operating expenses were offset partially by lower outside coal purchases in the 2013 Period.

	Nine Months Ended September 30,
	2013	2012		2013	2012
	(in thousands)			(per ton sold)
Tons sold	29,019	25,383		N/A	N/A
Tons produced	29,621	25,697		N/A	N/A
Coal sales	$1,594,530	$	1,441,107	$54.95	$56.77
Operating expenses and outside coal purchases	$1,044,085	$	981,565	$35.98	$38.67

Coal sales.  Coal sales for the 2013 Period increased 10.6% to $1.6 billion from $1.4 billion for the 2012 Period.  The increase of $153.4 million in coal sales reflected the benefit of increased tons sold (contributing $206.2 million in additional coal sales), partially offset by lower average coal sales prices (reducing coal sales by $52.8 million).  Average coal sales prices decreased $1.82 per ton sold to $54.95 per ton in the 2013 Period as compared to $56.77 per ton sold in the 2012 Period, primarily due to reduced coal sales into the metallurgical export market.

Operating expenses and outside coal purchases.  Operating expenses and outside coal purchases combined increased 6.4% to $1.0 billion for the 2013 Period from $981.6 million for the 2012 Period primarily due to record coal sales and production volumes.  On a per ton basis, operating expenses and outside coal purchases decreased 7.0% to $35.98 per ton sold.  Operating expenses were impacted by various other factors, the most significant of which are discussed below:

·Labor and benefit expenses per ton produced, excluding workers’ compensation, decreased 6.9% to $11.69 per ton in the 2013 Period from $12.56 per ton in the 2012 Period.  This decrease of $0.87 per ton was primarily attributable to lower labor cost per ton resulting from increased production at our Tunnel Ridge mine, which began longwall production in May 2012, improved coal recoveries from our River View and Gibson North mines and improved geological conditions at our Pattiki and Dotiki mines, lower labor cost per ton at our Onton

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mine despite a temporary halt of production in the 2013 Period and Pontiki’s lower cost per ton due to its temporary shutdown in the 2012 Period, both of which are discussed above, partially offset by higher employee benefits expense at our Mettiki mine, primarily medical related;

·Workers’ compensation expenses per ton produced decreased to $0.61 per ton in the 2013 Period from $1.00 per ton in the 2012 Period.  The decrease of $0.39 per ton produced resulted primarily from increased production discussed above and favorable claim trends;

·Material and supplies expenses per ton produced decreased 6.7% to $11.63 per ton in the 2013 Period from $12.46 per ton in the 2012 Period.  The decrease of $0.83 per ton produced resulted primarily from the benefits of increased production discussed above and a decrease in cost for certain products and services, primarily outside services (decrease of $0.27 per ton), certain ventilation-related materials and supplies (decrease of $0.18 per ton), roof support (decrease of $0.16 per ton) and power and fuel used in the mining process (decrease of $0.16 per ton);

·Maintenance expenses per ton produced decreased 6.9% to $3.94 per ton in the 2013 Period from $4.23 per ton in the 2012 Period.  The decrease of $0.29 per ton produced was primarily from the benefits of newer equipment and increased production at our new Tunnel Ridge mine and improved coal recoveries at certain locations as discussed above;

·Contract mining expenses decreased $4.5 million for the 2013 Period compared to the 2012 Period.  The decrease reflects lower production from a third-party mining operation in our Northern Appalachian region due to reduced metallurgical coal export market opportunities; and

·Outside coal purchases decreased to $2.0 million for the 2013 Period compared to $34.8 million in the 2012 Period.  The decrease of $32.8 million was primarily attributable to decreased coal brokerage activity and reduced sales into the metallurgical coal 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 2013 Period, generally reduce our overall total expenses per ton.

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

·Operating expenses for the 2013 Period included $3.8 million related to the retirement of certain assets resulting from the Onton mine’s previously mentioned temporary halt in production; and

·Capitalized development related to the construction of our new Tunnel Ridge mine ceased in May 2012 with the start-up of longwall production.  Accordingly, the above discussed operating expense decreases in the 2013 Period were offset partially by the capitalization of $19.0 million of mine development costs at Tunnel Ridge in the 2012 Period.

General and administrative.  General and administrative expenses for the 2013 Period increased to $46.7 million compared to $43.9 million in the 2012 Period.  The increase of $2.8 million was primarily due to increases in incentive compensation expense.

Other sales and operating revenues.  Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, Matrix Design sales and other outside services and administrative services revenue from affiliates.  Other sales and operating revenues decreased to $20.9 million for the 2013 Period from $26.1 million for the 2012 Period.  The decrease of $5.2 million was

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primarily attributable to amounts received from a customer in the 2012 Period for the partial buy-out of a certain Northern Appalachian coal contract.

Depreciation, depletion and amortization.  Depreciation, depletion and amortization expense increased to $198.7 million for the 2013 Period from $154.9 million for the 2012 Period.  The increase of $43.8 million was primarily attributable to additional depreciation related to the start-up of longwall production at the Tunnel Ridge mine, which began in May 2012, the addition of the Onton mine in April 2012 and capital expenditures related to production expansion and infrastructure improvements at various other operations.

Asset impairment charge.  In the 2012 Period, we recorded an asset impairment charge of $19.0 million associated with the long-lived assets at our Pontiki mining complex as discussed in more detail above and in “Item 1. Financial Statements (Unaudited) – Note 5. Asset Impairment Charge.”

Interest expense.  Interest expense, net of capitalized interest, decreased to $19.0 million for the 2013 Period from $21.6 million for the 2012 Period.  The decrease of $2.6 million was principally attributable to reduced interest expense resulting from our August 2013 and 2012 principal repayments of $18.0 million on our original senior notes issued in 1999, reduced interest expense resulting from lower rates and fees under our term loan and revolving credit facility entered into in May 2012, higher capitalized interest on our equity investment in White Oak in the 2013 Period and $1.1 million of deferred debt issuance costs related to the early termination of the $300 million term loan in the 2012 Period.  These decreases were partially offset by increased borrowings under our revolving credit facilities in the 2013 Period.  The term loan and revolving credit facilities are discussed in more detail 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 2013 Period, equity in loss of affiliates was $15.6 million compared to $11.0 million for the 2012 Period, which was primarily attributable to losses allocated to us due to our equity investment in White Oak.

Transportation revenues and expenses.  Transportation revenues and expenses were $23.5 million and $17.7 million for the 2013 and 2012 Periods, respectively.  The increase of $5.8 million was attributable to an increase in average transportation rates in the 2013 Period primarily related to new export sales from our Warrior mine, as well as increased tonnage for which we arranged transportation at certain other mines.  The cost of transportation services are passed through to our customers.  Consequently, we do not realize any gain or loss on transportation revenues.

Other income.  Other income decreased to $1.0 million in the 2013 Period from $2.9 million in the 2012 Period.  The decrease of $1.9 million was primarily due to the cancellation fee paid in the 2012 Period to the Intermediate Partnership by White Oak related to the termination of the equipment financing agreement.  For more information on White Oak, please read “Item 1. Financial Statements (Unaudited) – Note 8. White Oak Transactions” of this Quarterly Report on Form 10-Q.

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Segment Adjusted EBITDA.  Our 2013 Period Segment Adjusted EBITDA increased $79.3 million, or 16.6%, to $556.8 million from the 2012 Period Segment Adjusted EBITDA of $477.5 million.  Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are (in thousands):

	Nine Months Ended September 30,
	2013		2012		Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	488,634	$	419,955	$	68,679	16.4	%
Central Appalachia	29,691		25,618		4,073		15.9	%
Northern Appalachia	56,074		37,326		18,748		50.2	%
White Oak	(16,777)		(10,072)		(6,705)		(66.6	)%
Other and Corporate	(868)		4,661		(5,529)		(1	)
Elimination	-		-		-			-
Total Segment Adjusted EBITDA (2)	$	556,754	$	477,488	$	79,266	16.6	%
Tons sold
Illinois Basin	22,851		20,409		2,442		12.0	%
Central Appalachia	1,538		1,525		13		0.9	%
Northern Appalachia	4,607		3,239		1,368		42.2	%
White Oak	-		-		-			-
Other and Corporate	23		210		(187)		(89.0	)%
Elimination	-		-		-			-
Total tons sold	29,019		25,383		3,636		14.3	%
Coal sales
Illinois Basin	$	1,193,740	$	1,070,481	$	123,259	11.5	%
Central Appalachia	125,941		122,522		3,419		2.8	%
Northern Appalachia	272,826		230,677		42,149		18.3	%
White Oak	-		-		-			-
Other and Corporate	2,023		17,427		(15,404)		(88.4	)%
Elimination	-		-		-			-
Total coal sales	$	1,594,530	$	1,441,107	$	153,423	10.6	%
Other sales and operating revenues
Illinois Basin	$	2,704	$	1,704	$	1,000	58.7	%
Central Appalachia	537		16		521		(1	)
Northern Appalachia	2,604		9,098		(6,494)		(71.4	)%
White Oak	566		-		566		(1	)
Other and Corporate	24,672		29,248		(4,576)		(15.6	)%
Elimination	(10,217)		(13,933)		3,716		26.7	%
Total other sales and operating revenues	$	20,866	$	26,133	$	(5,267)	(20.2	)%
Segment Adjusted EBITDA Expense
Illinois Basin	$	707,810	$	652,231	$	55,579	8.5	%
Central Appalachia	96,786		96,920		(134)		(0.1	)%
Northern Appalachia	219,356		202,449		16,907		8.4	%
White Oak	1,074		(1,517)		2,591		(1	)
Other and Corporate	28,277		42,562		(14,285)		(33.6	)%
Elimination	(10,217)		(13,933)		3,716		26.7	%
Total Segment Adjusted EBITDA Expense (3)	$	1,043,086	$	978,712	$	64,374	6.6	%

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

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(2)Segment Adjusted EBITDA (a non-GAAP financial measure) is defined as net income before net interest expense, income taxes, depreciation, depletion and amortization, general and administrative expenses and asset impairment charge.  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:

·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 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):

	Nine Months Ended
	September 30,
	2013		2012
Segment Adjusted EBITDA	$	556,754	$	477,488
General and administrative	(46,736)		(43,939)
Depreciation, depletion and amortization	(198,688)		(154,923)
Asset impairment charge	-		(19,031)
Interest expense, net	(18,440)		(21,388)
Income tax benefit	1,307		726
Net income	$	294,197	$	238,933

(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 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):

	Nine Months Ended
	September 30,
	2013		2012
Segment Adjusted EBITDA Expense	$	1,043,086	$	978,712
Outside coal purchases	(2,028)		(34,759)
Other income	999		2,853
Operating expense (excluding depreciation, depletion and amortization)	$	1,042,057	$	946,806

Illinois Basin – Segment Adjusted EBITDA increased 16.4% to $488.6 million for the 2013 Period from $420.0 million for the 2012 Period.  This increase of $68.6 million was primarily attributable to increased tons sold, which increased 12.0% to 22.9 million tons in the 2013 Period, partially offset by lower contract pricing resulting in a lower average coal sales price of $52.24 per ton sold during the 2013 Period compared to $52.45 per ton sold for the 2012 Period.  Coal sales increased 11.5% to $1.2 billion in the 2013 Period compared to $1.1 billion in the 2012 Period.  The increase of $123.3 million primarily reflects increased tons sold and produced from our River View, Gibson North and Pattiki mines and the acquisition of the Onton mine.  Total Segment Adjusted EBITDA Expense for the 2013 Period increased 8.5% to $707.8 million from $652.2 million in the 2012 Period due to increased sales and production volumes noted above.  Although Segment Adjusted EBITDA Expense increased for the 2013 Period, Segment Adjusted EBITDA Expense per ton decreased $0.98 per ton sold to $30.98 from $31.96 per ton sold, primarily as a result of increased coal production discussed above as well as certain cost decreases partially offset by additional expenses and asset write-offs associated with the Onton mine’s temporary halt in production in the 2013 Quarter resulting from adverse geological conditions, all of which are discussed above under “-Operating expenses and outside coal purchases.”

Central Appalachia – Segment Adjusted EBITDA increased 15.9% to $29.7 million for the 2013 Period compared to $25.6 million for the 2012 Period.  The increase of $4.1 million was primarily attributable to higher average coal sales price of $81.87 per ton sold during the 2013 Period compared to $80.38 per ton sold for the 2012 Period and higher tons sold, which increased slightly in the 2013 Period resulting from a favorable mix of contract shipments.  Segment Adjusted EBITDA Expense per ton decreased $0.67 per ton sold to $62.92 per ton in the 2013 Period from $63.59 per ton sold in the 2012 Period, primarily as a result of the temporary idling at our Pontiki mine during the 2012 Period and reduced workers compensation expense in the 2013 Period. For additional detail related to the Pontiki mining complex read “Item 1. Financial Statements (Unaudited) – Note 5. Asset Impairment Charge.”

Northern Appalachia – Segment Adjusted EBITDA increased 50.2% to $56.1 million for the 2013 Period compared to $37.3 million for the 2012 Period.  The increase of $18.8 million was primarily attributable to increased tons sold and produced from our Tunnel Ridge mine, which began longwall production in May 2012, partially offset by lower average sales price of $59.22 per ton sold for the 2013 Period compared to $71.23 per ton sold for the 2012 Period due to reduced coal sales in the metallurgical export markets in the 2013 Period.  The start-up of longwall production at Tunnel Ridge was also the primary reason for the 8.4% increase in Segment Adjusted EBITDA Expense for the 2013 Period to $219.4 million from $202.4 million in the 2012 Period.  Although Segment Adjusted EBITDA Expense increased for the 2013 Period, Segment Adjusted EBITDA Expense per ton for the 2013 Period decreased $14.90 per ton sold to $47.61 for the 2013 Period from $62.51 per ton sold for the 2012 Period primarily due to lower cost per ton from longwall production at Tunnel Ridge and lower costs at our Mettiki mining complex due to reduced contract mining and coal processing expenses and lower outside coal purchases, all resulting primarily from reduced sales into metallurgical coal export markets, partially offset by higher employee benefit costs at Mettiki, primarily medical related.

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White Oak – Segment Adjusted EBITDA was $(16.8) million and $(10.1) million in the 2013 and 2012 Periods, respectively, primarily attributable to losses allocated to us due to our equity interest in White Oak.  For more information on White Oak, please read “Item 1. Financial Statements (Unaudited) – Note 8. White Oak Transactions” of this Quarterly Report on Form 10-Q.

Other and Corporate – Segment Adjusted EBITDA decreased $5.5 million in the 2013 Period from the 2012 Period.  This decrease was primarily attributable to lower coal brokerage sales and lower Matrix Group safety equipment sales.  Segment Adjusted EBITDA Expense decreased 33.6% to $28.3 million for the 2013 Period, primarily due to decreased outside coal purchases related to reduced coal brokerage activity.

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 the Annual Report on Form 10-K for the year ended December 31, 2012.

Cash Flows

Cash provided by operating activities was $550.4 million for the 2013 Period compared to $431.6 million for the 2012 Period.  Cash provided by operating activities primarily benefited from higher net income, reduced growth in coal inventory, an increase in the change in certain prepaid expenses and a decrease in trade receivables during the 2013 Period as compared to an increase during the 2012 Period, offset partially by a decrease in the change in accounts payable during the 2013 Period compared to the 2012 Period.

Net cash used in investing activities was $319.2 million for the 2013 Period compared to $511.4 million for the 2012 Period.  The decrease in cash used in investing activities was primarily attributable to a decrease in capital expenditures due to the completion of Tunnel Ridge mine development in May 2012, lower capital expenditures for mine infrastructure and equipment at various mines, particularly the Dotiki and River View mines, and the acquisition of the Onton mine in April 2012.

Net cash used in financing activities was $240.6 million for the 2013 Period compared to $191.7 million for the 2012 Period.  The increase in cash used in financing activities was primarily attributable to increased distributions paid to partners in the 2013 Period and net payments under our revolving credit facilities during the 2013 Period, which is discussed in more detail below under “–Debt Obligations.”

Capital Expenditures

Capital expenditures decreased to $242.7 million in the 2013 Period from $332.4 million in the 2012 Period.  See “–Cash Flows” above for additional information regarding capital expenditures.

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Our anticipated total capital expenditures for the year ending December 31, 2013 are estimated in a range of $370.0 to $400.0 million, which includes expenditures for mine expansion and infrastructure projects, maintenance capital, continued development of the Gibson South mine, and reserve acquisitions and construction of surface facilities related to the White Oak mine development project.  In addition, we have funded $47.5 million of preferred equity investments in White Oak during the 2013 Period bringing our total equity investment to date to $150.0 million.  Based on currently anticipated equity contributions by its partners, we do not expect to make further equity investments in White Oak during 2013.  Management anticipates funding remaining 2013 capital requirements with cash and cash equivalents ($18.9 million as of September 30, 2013), 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 Facilities.  On September 11, 2013, our Intermediate Partnership entered into a credit agreement for a $50.0 million revolving credit facility (“Facility”) to be used, as appropriate, for short-term working capital requirements.  The counterparty to the Facility is KC-LendCo, LLC, which is controlled by an officer of ARH via his role as independent trustee of irrevocable trusts established by our President and Chief Executive Officer.  Borrowings under the Facility bear interest at the London Interbank Offered Rate (“LIBOR”) plus 0.80%, with interest payable quarterly.  At September 30, 2013, the LIBOR with applicable margin was 0.98% on borrowings outstanding.  The lender and the Intermediate Partnership have the option to terminate the Facility at any time and the Facility was terminated on October 29, 2013, with all amounts outstanding, plus interest, paid in full.

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”).  The Credit Facility replaced the $142.5 million revolving credit facility that was scheduled to mature September 25, 2012 and the $300.0 million term loan agreement dated December 29, 2010 that was prepaid and terminated early on May 23, 2012.  The aggregate unpaid principal amount of $300.0 million and all unpaid interest was repaid using the proceeds of the Term Loan and borrowings under the Revolving Credit Facility.  Our Intermediate Partnership did not incur any early termination penalties in connection with the prepayment of the term loan.  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 1.84% on borrowings outstanding as of September 30, 2013.  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 quarter ending June 30, 2014 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.  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 September 30, 2013, we had borrowings of $150.0 million and $23.5 million of letters of credit outstanding with $576.5 million available for borrowing under the Revolving Credit Facility and the Facility.  We utilize the Revolving Credit Facility, as appropriate, for working capital requirements,

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capital expenditures, 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, payable in one remaining annual installment 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.

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, the incurrence of additional indebtedness and liens, the sale of assets, the making of investments, the entry into mergers and consolidations and the entry into 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 1.12 to 1.0 and 19.4 to 1.0, respectively, for the trailing twelve months ended September 30, 2013.  We were in compliance with the covenants of the ARLP Debt Arrangements as of September 30, 2013.

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 September 30, 2013, 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 a timesharing agreement for 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, 2012, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Related-Party Transactions” for additional information concerning related-party transactions.

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New Accounting Standards

New Accounting Standards Issued and Adopted

In February 2013, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”).  ASU 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income (“AOCI”) by component.  In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, certain significant amounts reclassified out of AOCI by the respective line items of net income.  ASU 2013-02 does not change the items that must be reported in AOCI.  ASU 2013-02 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2012.  The adoption of ASU 2013-02 did not have a material impact on our condensed consolidated financial statements.

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.

Insurance

Effective October 1, 2013, we renewed our annual property and casualty insurance program.  The aggregate maximum limit in the commercial property program is $100.0 million per occurrence, excluding a $1.5 million deductible for property damage, a 90 or 120 day waiting period for underground business interruption depending on the mining complex and a $10.0 million overall aggregate deductible.  We can make no assurances that we will not experience significant insurance claims in the future that could have a material adverse effect on our business, financial condition, results of operations and ability to purchase property insurance in the future.

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

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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 $150.0 million in borrowings under the revolving credit facilities and $250.0 million outstanding under the Term Loan Agreement at September 30, 2013.  A one percentage point increase in the interest rates related to the revolving credit facilities and Term Loan Agreement would result in an annualized increase in 2013 interest expense of $4.0 million, based on borrowing levels at September 30, 2013.  With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a decrease of approximately $10.2 million in the estimated fair value of these borrowings.

As of September 30, 2013, the estimated fair value of the ARLP Debt Arrangements was approximately $787.3 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 September 30, 2013.  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, 2012.

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 September 30, 2013.  Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective as of September 30, 2013.

During the quarterly period ended September 30, 2013, 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;

·unexpected changes in raw material costs;

·unexpected changes in the availability of skilled labor;

·our ability to maintain satisfactory relations with our employees;

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

·any unanticipated increases in transportation costs and risk of transportation delays or interruptions;

·unexpected 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;

·coal market’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;

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

·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 the Annual Report on Form 10-K for the year ended December 31, 2012.

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, 2012 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*
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 November 7, 2013, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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 November 7, 2013, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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 November 7, 2013, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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 November 7, 2013, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95.1	Federal Mine Safety and Health Act Information
101	Interactive Data File (Form 10-Q for the quarter ended September 30, 2013 filed in XBRL).

*       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 November 7, 2013.

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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