Edgar Filing: ALLIANCE RESOURCE PARTNERS LP

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2011

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

For the transition period from to

Commission File No.: 0-26823

ALLIANCE RESOURCE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware

73-1564280

(State or other jurisdiction of

incorporation or organization)

(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)

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 8, 2011, 36,775,741 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, 2011 and December 31, 2010		1

	Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2011 and 2010		2

	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010		3

	Notes to Condensed Consolidated Financial Statements		4

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk		36

ITEM 4.	Controls and Procedures		37

	Forward-Looking Statements		38

PART II

OTHER INFORMATION


ITEM 1.	Legal Proceedings	40

ITEM 1A.	Risk Factors	40

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40

ITEM 3.	Defaults upon Senior Securities	40

ITEM 4.	Reserved	40

ITEM 5.	Other Information	40

ITEM 6.	Exhibits	44

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,
	2011			2010
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	307,177		$	339,562
Trade receivables		144,201			112,942
Other receivables		2,336			2,537
Due from affiliates		116			1,912
Inventories		45,835			31,548
Advance royalties		4,812			4,812
Prepaid expenses and other assets		1,582			10,024

Total current assets		506,059			503,337

PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost		1,838,660			1,598,130
Less accumulated depreciation, depletion and amortization		(750,586	)		(648,883	)

Total property, plant and equipment, net		1,088,074			949,247

OTHER ASSETS:
Advance royalties		30,740			27,439
Equity investments in affiliates		37,119			—
Other long-term assets		17,173			21,255

Total other assets		85,032			48,694

TOTAL ASSETS	$	1,679,165		$	1,501,278


LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	86,425		$	63,339
Due to affiliates		514			573
Accrued taxes other than income taxes		18,073			13,901
Accrued payroll and related expenses		37,405			30,773
Accrued interest		6,644			2,491
Workers’ compensation and pneumoconiosis benefits		8,521			8,518
Current capital lease obligations		724			295
Other current liabilities		18,529			16,715
Current maturities, long-term debt		18,000			18,000

Total current liabilities		194,835			154,605

LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities		686,000			704,000
Pneumoconiosis benefits		49,106			45,039
Accrued pension benefit		10,489			13,296
Workers’ compensation		70,619			59,796
Asset retirement obligations		56,655			56,045
Due to affiliates		—			1,954
Long-term capital lease obligations		2,666			165
Other liabilities		3,568			10,595

Total long-term liabilities		879,103			890,890

Total liabilities		1,073,938			1,045,495


COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:
Limited Partners - Common Unitholders 36,775,741 and 36,716,855 units outstanding, respectively		904,873			761,875
General Partners’ deficit		(281,124	)		(287,371	)
Accumulated other comprehensive loss		(18,522	)		(18,721	)

Total Partners’ Capital		605,227			455,783

TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,679,165		$	1,501,278

See notes to condensed consolidated financial statements.

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,
	2011			2010			2011			2010

SALES AND OPERATING REVENUES:
Coal sales	$	473,683		$	396,655		$	1,323,851		$	1,146,719
Transportation revenues		7,446			7,111			25,452			25,637
Other sales and operating revenues		6,618			6,682			19,648			19,096

Total revenues		487,747			410,448			1,368,951			1,191,452


EXPENSES:
Operating expenses (excluding depreciation, depletion and amortization)		294,771			264,388			835,006			750,357
Transportation expenses		7,446			7,111			25,452			25,637
Outside coal purchases		19,864			5,736			29,495			12,122
General and administrative		13,276			14,304			38,698			36,633
Depreciation, depletion and amortization		40,275			37,587			117,237			109,560

Total operating expenses		375,632			329,126			1,045,888			934,309


INCOME FROM OPERATIONS		112,115			81,322			323,063			257,143

Interest expense (net of interest capitalized for the three and nine months ended September 30, 2011 and 2010 of $170, $67, $482 and $758, respectively)		(8,782	)		(7,633	)		(27,248	)		(22,667	)
Interest income		83			47			275			146
Other income		360			460			1,340			614

INCOME BEFORE INCOME TAXES		103,776			74,196			297,430			235,236

INCOME TAX EXPENSE (BENEFIT)		(317	)		995			(221	)		1,586


NET INCOME	$	104,093		$	73,201		$	297,651		$	233,650


GENERAL PARTNERS’ INTEREST IN NET INCOME	$	23,474		$	18,416		$	66,688		$	53,415


LIMITED PARTNERS’ INTEREST IN NET INCOME	$	80,619		$	54,785		$	230,963		$	180,235


BASIC NET INCOME PER LIMITED PARTNER UNIT (Note 8)	$	2.16		$	1.48		$	6.19		$	4.86


DILUTED NET INCOME PER LIMITED PARTNER UNIT (Note 8)	$	2.16		$	1.48		$	6.19		$	4.86


DISTRIBUTIONS PAID PER LIMITED PARTNER UNIT	$	0.9225		$	0.81		$	2.6725		$	2.375


WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING - BASIC		36,775,741			36,716,855			36,766,897			36,708,266


WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING - DILUTED		36,775,741			36,716,855			36,766,897			36,708,266

See notes to condensed consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2011			2010

CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	432,336		$	394,243


CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(216,308	)		(233,773	)
Changes in accounts payable and accrued liabilities		511			(6,298	)
Proceeds from sale of property, plant and equipment		465			353
Purchase of equity investment in affiliate		(35,700	)		—
Payment for acquisition of coal reserves		(33,841	)		—
Receipts of prior advances on Gibson rail project		810			1,597

Net cash used in investing activities		(284,063	)		(238,121	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facilities		—			95,000
Payments under revolving credit facilities		—			(95,000	)
Payments on capital lease obligations		(595	)		(242	)
Payment on long-term debt		(18,000	)		(18,000	)
Net settlement of employee withholding taxes on vesting of Long-Term Incentive Plan		(2,324	)		(1,265	)
Cash contributions by General Partners		87			43
Distributions paid to Partners		(159,826	)		(137,646	)

Net cash used in financing activities		(180,658	)		(157,110	)


EFFECT OF CURRENCY TRANSLATION ON CASH		—			(274	)


NET CHANGE IN CASH AND CASH EQUIVALENTS		(32,385	)		(1,262	)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		339,562			21,556


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	307,177		$	20,294


SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	22,930		$	19,354

Cash paid for income taxes	$	300		$	888


NON-CASH INVESTING AND FINANCING ACTIVITY:
Accounts payable for purchase of property, plant and equipment	$	12,828		$	14,521

Market value of common units issued under Long-Term Incentive Plan before minimum statutory tax withholding requirements	$	6,572		$	3,396

Assets acquired by capital lease	$	3,525		$	—

See notes to condensed consolidated financial statements.

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 was previously owned by our current and former management. In June 2006, our special general partner, SGP, and its parent, ARH, became wholly-owned, directly and indirectly, by Joseph W. Craft III, a director and the President and Chief Executive Officer of our managing general partner. SGP, a Delaware limited liability company, holds a 0.01% general partner interest in each of ARLP and the Intermediate Partnership. We have a time sharing agreement for the use of aircraft and we lease certain assets, including coal reserves and certain surface facilities, owned by SGP.

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, 2011 and December 31, 2010, results of our operations for the three and nine months ended September 30, 2011 and 2010 and cash flows for the nine months ended September 30, 2011 and 2010. All of our intercompany transactions and accounts have been eliminated.

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, 2010.

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 December 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-29, Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations (“ASU 2010-29”). ASU 2010-29 amended FASB’s Accounting Standards Codification (“ASC”) 805, Business Combinations, to specify that if a public entity presents comparative financial statements and a business combination has occurred during the current reporting period, then the public entity should disclose revenues and earnings of the combined entity as though the business combination that occurred during the current year had occurred at the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures under FASB ASC 805 to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenues and earnings. The adoption of the ASU 2010-29 amendments were effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. The adoption of ASU 2010-29 did not have an impact on our condensed consolidated financial statements.

New Accounting Standards Issued and Not Yet Adopted

In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 removes the presentation options in Accounting Standards Codification 220, Comprehensive Income, and requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. Under the two statement approach, the first statement would include components of net income, and the second statement would include components of other comprehensive income (“OCI”). ASU 2011-05 does not

change the items that must be reported in OCI. ASU 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, and its provisions must be applied retrospectively for all periods presented in the financial statements. We do not anticipate the adoption of ASU 2011-05 on January 1, 2012 will have a material impact on our 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. PATTIKI VERTICAL HOIST CONVEYOR SYSTEM FAILURE IN 2010

On May 13, 2010, White County Coal’s Pattiki mine was temporarily idled following the failure of the vertical hoist conveyor system used in conveying raw coal out of the mine. Our operating expenses for the nine months ended September 30, 2010 include $1.2 million for retirement of certain assets related to the failed vertical hoist conveyor system in addition to other repair and clean-up expenses that were not significant on a consolidated or segment basis. As the loss on the vertical hoist conveyor system did not exceed the deductible under our commercial property (including business interruption) insurance policies, we did not recover any amounts under such policies.

While the Pattiki mine was temporarily idled, we expanded coal production at our other coal mines in the region, including the addition of the seventh and eighth production units at the River View mine, to partially offset the loss of production from the Pattiki mine. Consequently, the temporary idling of the Pattiki mine in 2010 did not have a material adverse impact on our results of operations and cash flows. On July 19, 2010, the Pattiki mine resumed limited production while White County Coal continued to assess the effectiveness and reliability of the repaired vertical hoist conveyor system. On January 3, 2011, the Pattiki mine returned to full production.

5. FAIR VALUE MEASUREMENTS

We apply the provisions of FASB ASC 820, Fair Value Measurements and Disclosures, which, among other things, defines fair value, requires enhanced 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 and accounts payable approximate fair value because of the short maturity of those instruments. At September 30, 2011 and

December 31, 2010, the estimated fair value of our long-term debt, including current maturities, was approximately $741.5 million and $809.5 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 6).

6. LONG-TERM DEBT

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


	September 30, 2011			December 31, 2010
Credit facility	$	—		$	—
Senior notes		54,000			72,000
Series A senior notes		205,000			205,000
Series B senior notes		145,000			145,000
Term loan		300,000			300,000

		704,000			722,000
Less current maturities		(18,000	)		(18,000	)

Total long-term debt	$	686,000		$	704,000

On December 29, 2010, our Intermediate Partnership entered into a term loan agreement (the “Term Loan Agreement”) with various financial institutions for a term loan (the “Term Loan”) in the aggregate principal amount of $300 million. The Term Loan bears interest at a variable rate plus an applicable margin which fluctuates depending upon whether we elect the Term Loan (or a portion thereof) to bear interest at the Base Rate or the Eurodollar Rate (as defined in the Term Loan Agreement). We have elected the Eurodollar Rate which, with applicable margin, was 2.25% as of September 30, 2011. Interest is payable quarterly with principal due as follows: $15 million due per quarter beginning March 31, 2013 through December 31, 2013, $18.75 million due per quarter beginning March 31, 2014 through September 30, 2015 and the balance of $108.75 million due on December 31, 2015. 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 Term Loan Agreement. Upon a “change of control” (as defined in the Term Loan Agreement), the unpaid principal amount of the Term Loan, all interest thereon and all other amounts payable under the Term Loan Agreement will become due and payable.

We incurred debt issuance costs of approximately $1.4 million in 2010 associated with the Term Loan Agreement, which have been deferred and are being amortized as a component of interest expense over the duration of the Term Loan.

Our Intermediate Partnership has a $142.5 million revolving credit facility (the “ARLP Credit Facility”), $54.0 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”) and the $300 million Term Loan (collectively, the “ARLP Debt Arrangements”), which are guaranteed by all of the 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 the following: (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 4.0 to 1.0, in both cases, during the four most recently ended fiscal quarters. The ARLP Credit Facility, Senior Notes and the 2008 Senior Notes limit our Intermediate Partnership’s

maximum annual capital expenditures, excluding acquisitions. The amount of any annual limit in excess of actual capital expenditures for that year carries forward and is added to the annual limit of the subsequent year. As a result, the capital expenditure limit for 2011 is approximately $531.9 million. The debt to cash flow ratio and cash flow to interest expense ratio were 1.23 to 1.0 and 16.5 to 1.0, respectively, for the trailing twelve months ended September 30, 2011. Actual capital expenditures were $216.3 million for the nine months ended September 30, 2011. We were in compliance with the covenants of the ARLP Debt Arrangements as of September 30, 2011.

At September 30, 2011, we had $11.6 million of letters of credit outstanding with $130.9 million available for borrowing under the ARLP Credit Facility. We had no borrowings outstanding under the ARLP Credit Facility as of September 30, 2011 and December 31, 2010. We utilize the ARLP Credit Facility, as appropriate, to meet working capital requirements, anticipated capital expenditures, scheduled debt payments or distribution payments. We incur an annual commitment fee of 0.375% on the undrawn portion of the ARLP Credit Facility.

7. 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 leaseback of certain reserves and surface rights, a coal handling and services agreement and a backstop equipment financing facility. Our initial investment at the Transaction Date was $69.5 million and we committed to fund up to approximately $400.0 million to $525.0 million, including initial funding, over the next three to four years. The following information discusses each component of these transactions in further detail.

Hamilton County, Illinois Reserve Acquisition

Alliance Resource Properties, LLC (“Alliance Resource Properties”) newly formed subsidiary, Alliance WOR Properties, LLC (“WOR Properties”), acquired from White Oak the rights to approximately 100.0 million tons of proven and probable high-sulfur coal reserves and certain surface properties and rights in Hamilton County, Illinois (the “Reserve Acquisition”), which is adjacent to White County, Illinois, where our Pattiki mine is located. The asset purchase price of $33.8 million cash paid at closing was allocated to owned and leased coal rights. We utilized existing cash on hand to consummate the Reserve Acquisition.

In addition, WOR Properties committed up to $106.2 million to purchase, leaseback and fund development of up to an additional 100.0 million tons of coal reserves from White Oak during the next 12 to 24 months. In conjunction with the Reserve Acquisition, WOR Properties entered into a Coal Mining Lease, Sublease and Development Agreement (“Coal Lease Agreement”) with White Oak, which provides White Oak the rights to develop and mine the acquired reserves. The Coal Lease Agreement requires, in consideration of the leaseback of the coal reserves and the funding of development of those coal reserves, White Oak to pay WOR Properties earned royalties when coal production begins and a fully recoupable minimum monthly royalty of $1.625 million during the period beginning January 1, 2015 and ending December 31, 2034. The lease term is through December 31, 2034, subject to certain renewal options for White Oak.

Equity Investment – Series A Units

Concurrent with the Reserve Acquisition, Alliance WOR Processing, LLC (“WOR Processing”), a newly formed subsidiary of Alliance Coal, made an equity investment of $35.7 million in White Oak and received Series A Units representing ownership in White Oak. White Oak and WOR Processing agreed to an additional investment in Series A Units by WOR Processing of at least $114.3 million (for a minimum total of $150.0 million), and WOR Processing 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, and subject to certain rights and obligations of other White Oak owners to participate in such investment.

The Series A Units are entitled to receive 100% of all distributions made by White Oak until such time as the Series A Units have realized a defined minimum return, after which the Series A Units will receive distributions based on a participation percentage determined in accordance with the White Oak operating agreement. In addition, the Series A Units contain certain liquidation preferences that require upon an event of liquidation, the minimum return provision must be satisfied on a priority basis over other classes of White Oak equity. Assuming a $150.0 million investment in Series A Units, WOR Processing’s ownership interest in White Oak will be 20.0% and it will be entitled to receive 20.0% of all distributions subsequent to satisfaction of the Series A Units minimum return. WOR Processing’s ownership interest and distribution participation percentage in White Oak may increase with additional investments in the Series A Units up to a maximum of 40.0% for an investment of $275.0 million in the Series A Units. WOR Processing’s ownership and member’s voting interest in White Oak at September 30, 2011 was 5.6% 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.

There are four primary activities we believe that most significantly impact White Oak’s economic performance. These primary activities are associated with financing, capital, operating and marketing of White Oak’s development and operation of the mine areas covered by the agreements. We have various protective or participating rights related to these primary activities, such as minority representation on White Oak’s board of directors, restrictions on indebtedness and other obligations, the ability to assume control of White Oak’s board of directors in certain circumstances, such as an event of default by White Oak, and the right to approve certain coal sales agreements that represent a significant concentration of White Oak’s coal sales, among others. We undertook an extensive review of all such rights provided to WOR Processing and us and concluded all such rights are protective in nature and do not provide WOR Processing or us the ability to unilaterally direct any of the four primary activities of White Oak that most significantly impact its economic performance. However, the agreements provide us the ability to exert significant influence over these activities. As such, we recognize WOR Processing’s interest in White Oak as an equity investment in affiliate in our condensed consolidated balance sheet. We account for WOR Processing’s ownership interest in White Oak under the equity method of accounting, with recognition of its ownership interest in the income or loss of White Oak as equity income/(loss) in our condensed consolidated statements of income. As of September 30, 2011, WOR Processing had invested $35.7 million in Series A Units of White Oak equity, which represents our current maximum exposure to loss of White Oak. White Oak made no distributions from the Transaction Date through September 30, 2011.

We record WOR Processing’s equity in earnings or losses of affiliates under the hypothetical liquidation of book value (“HLBV”) method of accounting due to the preferences WOR Processing receives on distributions. Under the HLBV, we determine WOR Processing’s share of White Oak earnings or losses by determining the difference between its claim to White Oak’s book value at the end of the period as compared to the beginning of the period. WOR Processing’s claim on White Oak’s book value is calculated as the amount it would receive if White Oak were to liquidate all of its assets at recorded amounts determined in accordance with GAAP and distribute the resulting cash to creditors, other investors and WOR Processing according to the respective priorities. For the period from the Transaction Date through September 30, 2011, we were allocated losses of $0.2 million. There were no losses allocated to us for any period prior to the Transaction Date.

Throughput 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 will construct and operate a coal preparation plant and related facilities and a rail loop and loadout facility to service the White Oak mine. The Services Agreement requires White Oak to pay a throughput fee for these services of $5.00 per ton of feedstock coal processed through the preparation plant up to a minimum throughput quantity (and, beginning in January 2015, to pay any deficiency if less than the minimum tonnage is throughput) and $2.40 per ton for quantities in excess of the minimum throughput quantity. The minimum throughput quantity is 666,667 tons of feedstock coal per month. The term of the Services Agreement is through December 31, 2034. The expected cost to construct the facilities contemplated by the Services Agreement is approximately $99.5 million and will be expended by WOR Processing over the next three years utilizing existing cash on hand, cash generated from operations and cash from borrowings under our revolving credit facility. 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 not utilized any amounts available under the Construction Loan as of September 30, 2011.

Equipment Financing Commitment

Concurrent with the Reserve Acquisition, the Intermediate Partnership committed to provide $100.0 million of fully collateralized equipment financing with a five year term to White Oak for the purchase of coal mining equipment should other third party funding sources not be available. White Oak had not utilized any amounts available under the equipment financing as of September 30, 2011.

8. NET INCOME PER LIMITED PARTNER UNIT

We apply the provisions of FASB ASC 260, Earnings Per Share (“FASB ASC 260”), which require 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”), Supplemental Executive Retirement Plan (“SERP”) and the MGP Amended and Restated Deferred Compensation Plan for Directors (“Deferred Compensation Plan”) include rights to nonforfeitable distributions or distribution equivalents and are therefore considered participating securities. As such, we allocate undistributed and distributed earnings to these outstanding awards in our calculation of EPU.

The following is a reconciliation of net income used for calculating basic earnings per unit and the weighted average units used in computing EPU for the three and nine months ended September 30, 2011 and 2010, respectively, (in thousands, except per unit data):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010

Net income	$	104,093		$	73,201		$	297,651		$	233,650
Adjustments:
General partner’s priority distributions		(21,829	)		(17,297	)		(61,975	)		(49,736	)
General partners’ 2% equity ownership		(1,645	)		(1,119	)		(4,713	)		(3,679	)


Limited partners’ interest in net income		80,619			54,785			230,963			180,235

Less:
Distributions to participating securities		(501	)		(314	)		(1,462	)		(923	)
Undistributed earnings attributable to participating securities		(642	)		(245	)		(1,833	)		(919	)


Net income available to limited partners	$	79,476		$	54,226		$	227,668		$	178,393

Weighted average limited partner units outstanding – basic and diluted		36,776			36,717			36,767			36,708

Basic and diluted net income per limited partner unit ⁽¹⁾	$	2.16		$	1.48		$	6.19		$	4.86

(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, 2011, LTIP, SERP and Deferred Compensation Plan units of 411,043 and 403,301, respectively, were considered anti-dilutive. For the three and nine months ended September 30, 2010, LTIP units of 253,294 and 219,187, respectively, were considered anti-dilutive.

9. 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,
	2011			2010			2011			2010

Beginning balance	$	74,515		$	70,050		$	67,687		$	63,220
Accruals increase		5,570			5,120			16,684			14,931
Payments		(2,491	)		(2,494	)		(8,519	)		(7,312	)
Interest accretion		793			833			2,380			2,499
Valuation loss		125			2,015			280			2,186

Ending balance	$	78,512		$	75,524		$	78,512		$	75,524

Pneumoconiosis

The Patient Protection and Affordable Care Act, which was signed into law by President Obama on March 23, 2010, amended previous legislation related to coal workers’ pneumoconiosis, or black lung,

providing automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims. The impact of these changes to our current population of beneficiaries and claimants resulted in an estimated $8.3 million increase to our black lung obligation at December 31, 2010. We recorded this estimate as an increase to our black lung liability and a decrease to our actuarial gain included in accumulated other comprehensive income on our December 31, 2010 condensed consolidated balance sheet. This increase to our obligation excludes the impact of potential re-filing of closed claims and potential filing rates for employees who terminated more than seven years ago as we do not have sufficient information to determine what, if any, claims will be filed until regulations are issued or development patterns are identified through future litigation of claims. We will continue to evaluate the impact of these changes on such claims and record any necessary changes in the period in which the impact is estimable. For more information, please read “Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Other—Health Care Reform” of this Quarterly Report on Form 10-Q.

10. 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 (“Compensation Committee”). On January 25, 2011, the Compensation Committee determined that the vesting requirements for the 2008 grants of 91,100 units (which are net of 2,500 forfeitures) had been satisfied as of January 1, 2011. As a result of this vesting, on February 11, 2011, we issued 58,886 unrestricted common units to LTIP participants. The remaining units were settled in cash to satisfy the individual tax withholding obligations for the LTIP participants. On January 25, 2011, the Compensation Committee authorized additional grants of up to 110,000 restricted units, of which 108,416 were granted during the nine months ended September 30, 2011, all of which will vest on January 1, 2014 subject to satisfaction of certain financial tests. The fair value of these 2011 grants is equal to the intrinsic value at the date of grant, which was $66.84 per unit. LTIP expense was $1.3 million and $1.0 million for the three months ended September 30, 2011 and 2010, respectively, and $3.9 million and $2.9 million for the nine months ended September 30, 2011 and 2010, respectively. After consideration of the January 1, 2011 vesting and subsequent issuance of 58,886 common units, approximately 2.2 million units remain available for issuance under the LTIP in the future, assuming all grants issued in 2009, 2010 and 2011 currently outstanding are settled with common units and no future forfeitures occur.

As of September 30, 2011, there was $7.8 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 1.1 years. As of September 30, 2011, the intrinsic value of the non-vested LTIP grants was $25.2 million. As of September 30, 2011, the total obligation associated with the LTIP was $8.2 million and is included in the partners’ capital-limited partners line item in our condensed consolidated balance sheets.

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

SERP and Directors Deferred Compensation Plan

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

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 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.

Amounts that were payable under either the SERP or Deferred Compensation Plan on or prior to January 1, 2011, were paid in either cash or common units of ARLP. Effective for amounts that become payable after January 1, 2011, both the Deferred Compensation Plan and the SERP require that vested benefits be paid to participants only in common units of ARLP, and therefore the phantom units now qualify for equity award accounting treatment. As a result, we reclassified a total of $9.2 million of obligations for the SERP and the Deferred Compensation Plan from due to affiliates and other long-term liabilities to partners’ capital in our condensed consolidated balance sheets as required under FASB ASC 718, Compensation-Stock Compensation, on January 1, 2011. For the nine months ended September 30, 2011 and 2010, SERP and Deferred Compensation Plan participant notional account balances were credited with a total of 8,284 and 9,091 phantom units, respectively, and the fair value of these phantom units was $72.01 and $58.34, respectively, on a weighted-average basis. Total SERP and Deferred Compensation Plan expense was approximately $0.2 million and $2.1 million for the three months ended September 30, 2011 and 2010, respectively, and $0.6 million and $2.7 million for the nine months ended September 30, 2011 and 2010, respectively.

As of September 30, 2011, there were 148,534 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 $9.7 million. As of September 30, 2011, the total obligation associated with the SERP and Deferred Compensation Plan was $9.8 million and is included in the partners’ capital-limited partners line item in our condensed consolidated balance sheets.

11. 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,
	2011			2010			2011			2010
Service cost	$	618		$	713		$	1,854		$	2,139
Interest cost		788			839			2,364			2,519
Expected return on plan assets		(972	)		(922	)		(2,917	)		(2,768	)
Amortization of net loss		122			269			366			806

Net periodic benefit cost	$	556		$	899		$	1,667		$	2,696

We previously disclosed in our financial statements for the year ended December 31, 2010 that we expected to contribute $5.0 million to the Pension Plan in 2011. During the nine months ended September 30, 2011, we made contribution payments of $2.6 million for the 2010 plan year and $1.6 million for the 2011 plan year. On October 14, 2011, we made a payment of $0.8 million for the 2011 plan year, for total contributions of $5.0 million to the Pension Plan in 2011 for the 2010 and 2011 plan years.

12. COMPREHENSIVE INCOME

Total comprehensive income for the three and nine months ended September 30, 2011 and 2010, respectively, is as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Net income	$	104,093	$	73,201	$	297,651	$	233,650
Other comprehensive income:
Actuarially determined long-term liability adjustments		66		1,879		199		2,417

Total other comprehensive income		66		1,879		199		2,417

Comprehensive income	$	104,159	$	75,080	$	297,850	$	236,067

Comprehensive income differs from net income due to net amortization of actuarial gains and losses associated with adoption of amendments to FASB ASC 715, Compensation – Retirement Benefits.

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 four reportable segments: Illinois Basin, Central Appalachia, Northern Appalachia 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 Illinois Basin reportable segment is comprised of multiple operating segments, including Webster County Coal, LLC’s Dotiki mining complex, Gibson County Coal, LLC’s Gibson North mining complex, Hopkins County Coal, LLC’s Elk Creek mining complex, White County Coal, LLC’s Pattiki mining complex, Warrior Coal, LLC’s mining complex, River View Coal, LLC’s mining complex, the Sebree Mining, LLC (“Sebree”) property, the Gibson County Coal (South), LLC (“Gibson South”) property and certain properties of Alliance Resource Properties and its wholly-owned subsidiary, ARP Sebree, LLC. We recently received the permits necessary to begin mine construction at the Gibson South property, and on July 25, 2011, the board of directors of our managing general partner approved development of this mine, which is currently underway. We are in the process of permitting the Sebree property for future mine development.

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

The Northern Appalachian reportable segment is comprised of multiple operating segments, including Mettiki Coal, LLC’s mining complex, Mettiki Coal (WV) LLC’s Mountain View mining complex, two small third-party mining operations (one of which ceased operations in July 2011), a mining complex currently under construction at Tunnel Ridge, LLC (“Tunnel Ridge”) and the Penn Ridge Coal, LLC (“Penn Ridge”) property. In May 2010, incidental production began from mine development activities at Tunnel Ridge; however, longwall production is not anticipated until early in the second quarter of 2012. We are in the process of permitting the Penn Ridge property for future mine development.

Other and Corporate includes marketing and administrative expenses, 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”), the Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) dock activities, coal brokerage activity, WOR Properties, WOR Processing, our equity investment in Mid-America Carbonates, LLC (“MAC”) and certain properties of Alliance Resource Properties. WOR Processing includes both our surface operations at White Oak currently under construction and our equity investment in White Oak (Note 7). Reportable segment results as of and for the three and nine months ended September 30, 2011 and 2010 are presented below.


	Illinois Basin		Central Appalachia		Northern Appalachia		Other and Corporate			Elimination (1)			Consolidated
	(in thousands)
Reportable segment results for the three months ended September 30, 2011:

Total revenues (2)	$	342,237	$	49,478	$	76,808	$	22,696		$	(3,472	)	$	487,747
Segment Adjusted EBITDA Expense (3)		210,024		36,796		50,911		20,016			(3,472	)		314,275
Segment Adjusted EBITDA (4)		127,230		12,456		23,665		2,675			—			166,026
Capital expenditures		36,050		8,298		29,044		34,324	*		—			107,716	*


Reportable segment results for the three months ended September 30, 2010:

Total revenues (2)	$	304,292	$	41,499	$	57,248	$	12,702		$	(5,293	)	$	410,448
Segment Adjusted EBITDA Expense (3)		185,183		33,175		46,268		10,331			(5,293	)		269,664
Segment Adjusted EBITDA (4)		114,215		8,307		8,781		2,370			—			133,673
Capital expenditures		35,611		3,389		19,512		413			—			58,925

Reportable segment results as of and for the nine months ended September 30, 2011:

Total revenues (2)	$	983,038	$	154,704	$	200,004	$	43,340		$	(12,135	)	$	1,368,951
Segment Adjusted EBITDA Expense (3)		583,291		109,848		143,804		38,353			(12,135	)		863,161
Segment Adjusted EBITDA (4)		382,164		43,590		49,602		4,982			—			480,338
Total assets		787,790		89,516		400,372		402,364			(877	)		1,679,165
Capital expenditures		109,404		20,153		84,817		35,775	*		—			250,149	*

Reportable segment results as of and for the nine months ended September 30, 2010:

Total revenues (2)	$	895,878	$	122,189	$	156,223	$	34,048		$	(16,886	)	$	1,191,452
Segment Adjusted EBITDA Expense (3)		532,626		97,921		119,855		28,349			(16,886	)		761,865
Segment Adjusted EBITDA (4)		344,216		24,141		29,892		5,701			—			403,950
Total assets		753,987		84,505		299,812		43,203			(5,401	)		1,176,106
Capital expenditures		119,000		7,909		105,503		1,361			—			233,773

*	Capital expenditures shown above for the three and nine months ended September 30, 2011, include the reserves ‘acquired from White Oak for $33,841 (Note 7).

(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 September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010

Segment Adjusted EBITDA Expense	$	314,275		$	269,664		$	863,161		$	761,865
Outside coal purchases		(19,864	)		(5,736	)		(29,495	)		(12,122	)
Other income		360			460			1,340			614

Operating expenses (excluding depreciation, depletion and amortization)	$	294,771		$	264,388		$	835,006		$	750,357

(4)

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010

Segment Adjusted EBITDA	$	166,026		$	133,673		$	480,338		$	403,950
General and administrative		(13,276	)		(14,304	)		(38,698	)		(36,633	)
Depreciation, depletion and amortization		(40,275	)		(37,587	)		(117,237	)		(109,560	)
Interest expense, net		(8,699	)		(7,586	)		(26,973	)		(22,521	)
Income tax (expense) benefit		317			(995	)		221			(1,586	)

Net income	$	104,093		$	73,201		$	297,651		$	233,650

14. SUBSEQUENT EVENTS

On October 28, 2011, we declared a quarterly distribution for the quarter ended September 30, 2011, of $0.955 per unit, on all common units outstanding, totaling approximately $57.7 million (which includes our managing general partner’s incentive distributions), payable on November 14, 2011 to all unitholders of record as of November 7, 2011.

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 “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 “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 fourth largest coal producer in the eastern U.S. We operate nine underground mining complexes in Illinois, Indiana, Kentucky, Maryland and West Virginia. We are constructing a new mining complex in West Virginia, and we also operate a coal loading terminal on the Ohio River at Mt. Vernon, Indiana. In addition, on July 25, 2011, the board of directors of our managing general partner (“Board of Directors”) approved development of a new mine in Indiana. As is customary in the coal industry, we have entered into long-term coal supply agreements with many of our customers.

We have four reportable segments: Illinois Basin, Central Appalachia, Northern Appalachia 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.

•

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 Gibson North mining complex (“Gibson North”), Hopkins County Coal, LLC’s Elk Creek mining complex (“Hopkins”), White County Coal, LLC’s Pattiki mine (“Pattiki”), Warrior Coal, LLC’s mining complex (“Warrior”), River View Coal, LLC’s mining complex (“River View”), the Sebree Mining, LLC (“Sebree”) property, the Gibson County Coal (South), LLC (“Gibson South”) property and certain properties of Alliance Resource Properties, LLC (“Alliance Resource Properties”) and its wholly-owned subsidiary, ARP Sebree, LLC. We recently received the permits necessary to begin mine construction at the Gibson South property, and on July 25, 2011, the Board of Directors approved development of this mine, which is currently underway. We are in the process of permitting the Sebree property for future mine development.

•

Central Appalachian reportable segment is comprised of two operating segments, Pontiki Coal, LLC’s (“Pontiki”) and MC Mining, LLC’s mining complexes.

•

Northern Appalachian reportable segment is comprised of multiple operating segments, including Mettiki Coal, LLC’s mining complex (“Mettiki”), Mettiki Coal (WV), LLC’s Mountain View mining complex (“Mountain View”), two small third-party mining operations (one of which ceased operations in July 2011), a mining complex currently under construction at Tunnel Ridge, LLC (“Tunnel Ridge”) and the Penn Ridge Coal, LLC (“Penn Ridge”) property. In May 2010, incidental production began from mine development activities at Tunnel Ridge; however, longwall production is not anticipated until early in the second quarter of 2012. We are in the process of permitting the Penn Ridge property for future mine development.

•

Other and Corporate reportable segment includes marketing and administrative expenses, 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”), the Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) dock activities, coal brokerage activity, Alliance WOR Properties, LLC, Alliance WOR Processing, LLC (“WOR Processing”), our equity investment in Mid-America Carbonates, LLC (“MAC”) and certain properties of Alliance Resource Properties. WOR Processing includes both our surface operations at White Oak Resources, LLC (“White Oak”) currently under construction and our equity investment in White Oak. For more information on White Oak, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 7. White Oak Transactions” of this Quarterly Report on Form 10-Q.

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

We reported record net income of $104.1 million for the three months ended September 30, 2011 (“2011 Quarter”) compared to $73.2 million for the three months ended September 30, 2010 (“2010 Quarter”). This increase of $30.9 million was principally due to improved pricing resulting in a record quarterly average coal sales price of $56.89 per ton sold, as compared to $51.68 per ton sold for the 2010 Quarter, and record coal sales volumes, which increased to 8.3 million tons for the 2011 Quarter compared to 7.7 million tons for the 2010 Quarter. We had higher tons produced of 7.6 million tons in the 2011 Quarter, compared to 7.1 million tons produced in the 2010 Quarter. The increase in produced tons primarily reflects increased production from our River View, Pattiki and Gibson North mines. Higher operating expenses during the 2011 Quarter resulted primarily from increased sales and production volumes, which particularly impacted materials and supplies expenses, sales-related expenses, maintenance costs and labor-related expenses. Increased operating expenses also reflect increased incidental production at our Tunnel Ridge mine development project and higher outside coal purchases.


	Three Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)				(per ton sold)
Tons sold		8,326		7,676		N/A		N/A
Tons produced		7,644		7,124		N/A		N/A
Coal sales	$	473,683	$	396,655	$	56.89	$	51.68
Operating expenses and outside coal purchases	$	314,635	$	270,124	$	37.79	$	35.19

Coal sales. Coal sales for the 2011 Quarter increased 19.4% to $473.7 million from $396.7 million for the 2010 Quarter. The increase of $77.0 million in coal sales reflected the benefit of record coal sales prices (contributing $43.4 million in coal sales) and tons sold (contributing $33.6 million in

additional coal sales). Average coal sales prices in the 2011 Quarter increased $5.21 per ton sold to $56.89 per ton in the 2011 Quarter compared to $51.68 per ton in the 2010 Quarter primarily as a result of improved contract pricing across all regions, particularly increased pricing of coal sold into the export market.

Operating expenses and outside coal purchases. Operating expenses and outside coal purchases increased 16.5% to $314.6 million for the 2011 Quarter from $270.1 million for the 2010 Quarter primarily due to record coal sales, increased production volumes and higher outside coal purchases. On a per ton basis, operating expenses and outside coal purchases increased 7.4% to $37.79 per ton sold. Various significant factors related to the operating and outside coal purchases expense and per ton variances are discussed below:

•

Labor and benefit expenses per ton produced, excluding workers’ compensation, increased 13.3% to $12.54 per ton in the 2011 Quarter from $11.07 per ton in the 2010 Quarter. This increase of $1.47 per ton represents increased labor costs and health care costs at our Illinois Basin mines, higher mine development labor and benefits at our Tunnel Ridge mine and the impact of decreased coal recoveries at our Dotiki, Warrior and Gibson mines, partially offset by increased production at our Pattiki and Central Appalachian mines;

•

Workers’ compensation expenses per ton produced decreased to $1.09 per ton in the 2011 Quarter from $1.31 per ton in the 2010 Quarter. The decrease of $0.22 per ton produced resulted primarily from unfavorable reserve adjustments for claims incurred during the 2010 Quarter;

•

Material and supplies expenses per ton produced increased 11.4% to $12.33 per ton in the 2011 Quarter from $11.07 per ton in the 2010 Quarter. The increase of $1.26 per ton produced resulted from an increase in costs for certain products and services, primarily roof support (increase of $0.40 per ton), certain safety related materials and supplies (increase of $0.32 per ton), contract labor used in the mining process (increase of $0.27 per ton), power and fuel used in the mining process (increase of $0.19 per ton) and ventilation (increase of $0.14 per ton) in addition to the negative cost impact of heightened regulatory oversight;

•

Maintenance expenses per ton produced increased 11.5% to $4.18 per ton in the 2011 Quarter from $3.75 per ton in the 2010 Quarter. The increase of $0.43 per ton produced was primarily due to higher maintenance costs in various equipment categories in the Illinois Basin and Northern Appalachian regions;

•

Mine administration expenses increased $1.9 million for the 2011 Quarter compared to the 2010 Quarter, primarily due to increased regulatory costs across all regions, increased costs associated with Matrix Design products and research, and higher insurance costs;

•

Production taxes and royalties expenses (which were incurred as a percentage of coal sales prices and volumes) increased $0.17 per produced ton sold in the 2011 Quarter compared to the 2010 Quarter primarily as a result of increased average coal sales prices across all regions;

•

The operating expenses increases described above were partially offset in the 2011 Quarter by a decrease in contract mining expenses of $1.5 million for the 2011 Quarter compared to the 2010 Quarter due principally to decreased production expenses at our third-party mining operations and the closure of one third-party mining operation in the Northern Appalachian region during July 2011; and

•

Outside coal purchases increased to $19.9 million for the 2011 Quarter from $5.7 million in the 2010 Quarter. The increase of $14.2 million was primarily attributable to increased coal brokerage activity as well as Mettiki’s higher cost per ton of coal purchased.

General and administrative. General and administrative expenses for the 2011 Quarter decreased to $13.3 million compared to $14.3 million in the 2010 Quarter. The decrease of $1.0 million was primarily due to decreases in expense for certain incentive compensation plans and lower contributions to industry and advocacy groups.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $40.3 million for the 2011 Quarter from $37.6 million for the 2010 Quarter. The increase of $2.7 million was attributable to additional depreciation expense associated with capital expenditures related to the expansion of our River View mine and capital expenditures related to various infrastructure improvements and efficiency projects at other mining operations.

Interest expense. Interest expense, net of capitalized interest, increased to $8.8 million for the 2011 Quarter from $7.6 million for the 2010 Quarter. The increase of $1.2 million was principally attributable to increased interest expense resulting from our $300 million term loan, which was completed in the fourth quarter of 2010, partially offset by reduced interest expense resulting from our August 2011 principal repayment of $18.0 million on our original senior notes issued in 1999, each of which is discussed in more detail below under “–Debt Obligations.”

Transportation revenues and expenses. Transportation revenues and expenses were $7.4 million and $7.1 million for the 2011 and 2010 Quarters, respectively. The increase of $0.3 million was primarily attributable to an increase in average transportation rates of $0.50 per ton in the 2011 Quarter compared to the 2010 Quarter reflecting in part higher fuel costs, offset by reduced tonnage in the 2011 Quarter for which we arranged tonnage compared to the 2010 Quarter. The cost of transportation services are passed through to our customers. Consequently, we do not realize any gain or loss on transportation revenues.

Income tax expense (benefit). The income tax benefit was $0.3 million for the 2011 Quarter compared to income tax expense of $1.0 million for the 2010 Quarter. Income taxes are primarily due to the operations of Matrix Design, which is owned by our subsidiary, Alliance Service, Inc. The income tax benefit was due to operating losses in the 2011 Quarter from our Matrix Design operation.

Segment Adjusted EBITDA. Our 2011 Quarter Segment Adjusted EBITDA increased $32.3 million, or 24.2%, to a record $166.0 million from the 2010 Quarter Segment Adjusted EBITDA of $133.7 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,
	2011			2010			Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	127,230		$	114,215		$	13,015		11.4	%
Central Appalachia		12,456			8,307			4,149		49.9	%
Northern Appalachia		23,665			8,781			14,884		(1	)
Other and Corporate		2,675			2,370			305		12.9	%
Elimination		—			—			—		—

Total Segment Adjusted EBITDA (2)	$	166,026		$	133,673		$	32,353		24.2	%


Tons sold
Illinois Basin		6,631			6,276			355		5.7	%
Central Appalachia		616			531			85		16.0	%
Northern Appalachia		820			837			(17	)	(2.0	)%
Other and Corporate		259			32			227		(1	)
Elimination		—			—			—		—

Total tons sold		8,326			7,676			650		8.5	%


Coal sales
Illinois Basin	$	337,029		$	299,161		$	37,868		12.7	%
Central Appalachia		49,252			41,481			7,771		18.7	%
Northern Appalachia		73,731			54,126			19,605		36.2	%
Other and Corporate		13,671			1,887			11,784		(1	)
Elimination		—			—			—		—

Total coal sales	$	473,683		$	396,655		$	77,028		19.4	%


Other sales and operating revenues
Illinois Basin	$	226		$	238		$	(12	)	(5.0	)%
Central Appalachia		—			—			—		—
Northern Appalachia		845			923			(78	)	(8.5	)%
Other and Corporate		9,019			10,814			(1,795	)	(16.6	)%
Elimination		(3,472	)		(5,293	)		1,821		34.4	%

Total other sales and operating revenues	$	6,618		$	6,682		$	(64	)	(1.0	)%


Segment Adjusted EBITDA Expense
Illinois Basin	$	210,024		$	185,183		$	24,841		13.4	%
Central Appalachia		36,796			33,175			3,621		10.9	%
Northern Appalachia		50,911			46,268			4,643		10.0	%
Other and Corporate		20,016			10,331			9,685		93.7	%
Elimination		(3,472	)		(5,293	)		1,821		34.4	%

Total Segment Adjusted EBITDA Expense (3)	$	314,275		$	269,664		$	44,611		16.5	%

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

(2)

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

•

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 as 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 above 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,
	2011			2010
Segment Adjusted EBITDA	$	166,026		$	133,673
General and administrative		(13,276	)		(14,304	)
Depreciation, depletion and amortization		(40,275	)		(37,587	)
Interest expense, net		(8,699	)		(7,586	)
Income tax (expense) benefit		317			(995	)

Net income	$	104,093		$	73,201

(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.

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,
	2011			2010
Segment Adjusted EBITDA Expense	$	314,275		$	269,664
Outside coal purchases		(19,864	)		(5,736	)
Other income		360			460

Operating expense (excluding depreciation, depletion and amortization)	$	294,771		$	264,388

Illinois Basin – Segment Adjusted EBITDA increased 11.4% to $127.2 million in the 2011 Quarter from $114.2 million in the 2010 Quarter. This increase of $13.0 million was primarily attributable to increased contract pricing reflecting a higher average sales price of $50.83 per ton sold for the 2011 Quarter compared to $47.67 per ton sold for the 2010 Quarter, as well as higher tons sold which increased 5.7% to 6.6 million tons in the 2011 Quarter. Coal sales increased 12.7% to $337.0 million in the 2011 Quarter compared to $299.2 million in the 2010 Quarter. The increase of $37.8 million primarily reflects the increase in the average coal sales price discussed above and increased tons produced and sold from the expansion of production capacity at our River View mine and resumption of full production at our Pattiki mine in the first quarter of 2011, offset partially by difficult mining conditions affecting certain other mining operations. Total Segment Adjusted EBITDA Expense for the 2011 Quarter increased 13.4% to $210.0 million from $185.2 million in the 2010 Quarter and increased $2.16 per ton sold to $31.67 from $29.51 per ton sold, primarily as a result of certain cost increases described above under consolidated operating expenses. In addition, increased labor costs combined with lower production and coal recoveries at our Warrior and Dotiki mines due to difficult mining conditions increased Segment Adjusted EBITDA Expense per ton, partially offset by higher production at our River View, Gibson North and Pattiki mines.

Central Appalachia – Segment Adjusted EBITDA increased 49.9% to $12.5 million for the 2011 Quarter compared to $8.3 million in the 2010 Quarter. The increase of $4.2 million was primarily attributable to increased tons sold, which increased 16.0% to 0.6 million tons sold in the 2011 Quarter, as well as improved contract pricing resulting in a higher average coal sales price of $79.99 per ton sold during the 2011 Quarter compared to $78.18 per ton sold for the 2010 Quarter. Total Segment Adjusted EBITDA Expense for the 2011 Quarter increased 10.9% to $36.8 million from $33.2 million in the 2010 Quarter, primarily as a result of increased sales volumes and certain cost increases described above under consolidated operating expenses, particularly the impact of increasingly stringent regulatory compliance. Although Segment Adjusted EBITDA Expense increased, Segment Adjusted EBITDA expense per ton decreased 4.4% to $59.76 per ton in the 2011 Quarter from $62.52 per ton in the 2010 Quarter, primarily as a result of increased production at both Central Appalachian mines and particularly Pontiki, which added a fourth mining unit during the quarter ended June 30, 2011.

Northern Appalachia – Segment Adjusted EBITDA increased to $23.7 million for the 2011 Quarter as compared to $8.8 million in the 2010 Quarter. This increase of $14.9 million was primarily attributable to improved contract pricing in the export coal markets resulting in a higher average sales price of $89.89 per ton sold for the 2011 Quarter compared to $64.63 per ton sold for the 2010 Quarter. Total Segment Adjusted EBITDA Expense for the 2011 Quarter increased 10.0% to $50.9 million from $46.3 million in the 2010 Quarter and increased $6.82 per ton sold to $62.07 from $55.25 per ton sold, primarily as a result of increased cost per ton of coal purchased for sale, the impact of seasonal miners’ vacation and a longwall move at our Mountain View mine. Total Segment Adjusted EBITDA Expense for the 2011 Quarter was also impacted by the other cost increases described above under consolidated operating expenses, including expenses related to our Tunnel Ridge mine development project, offset in part by improved coal recoveries in the 2011 Quarter compared to the 2010 Quarter.

Other and Corporate – Segment Adjusted EBITDA increased $0.3 million in the 2011 Quarter from the 2010 Quarter. This increase was primarily attributable to higher coal brokerage sales. Other sales and operating revenues decreased 16.6% to $9.0 million in the 2011 Quarter compared to $10.8 million for the 2010 Quarter. The decrease of $1.8 million was primarily attributable to decreased sales of mine safety equipment by the Matrix Group to our other mining subsidiaries (which are eliminated upon consolidation). Segment Adjusted EBITDA Expense increased 93.7% to $20.0 million for the 2011 Quarter compared to $10.3 million for the 2010 Quarter, primarily due to higher coal brokerage expenses associated with increased brokerage coal sales as well as increased component expenses and research costs associated with services revenue and safety equipment sales by the Matrix Group.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

We reported record net income of $297.7 million for the nine months ended September 30, 2011 (“2011 Period”) compared to $233.7 million for the nine months ended September 30, 2010 (“2010 Period”). This increase of $64.0 million was principally due to improved pricing resulting in an average coal sales price of $55.73 per ton sold for the 2011 Period, as compared to $50.86 per ton sold in the 2010 Period. We had tons sold of 23.8 million and tons produced of 23.4 million in the 2011 Period compared to 22.5 million tons sold and 21.6 million tons produced in the 2010 Period. This increase in produced tons primarily reflects increased production from our River View mine. Higher operating expenses during the 2011 Period resulted primarily from increased sales and production volumes, which particularly impacted materials and supplies expenses, sales-related expenses, maintenance costs and labor costs. Increased operating expenses also reflect increased incidental production at our Tunnel Ridge mine development project and higher outside coal purchases.


	Nine Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)				(per ton sold)
Tons sold		23,754		22,545		N/A		N/A
Tons produced		23,398		21,585		N/A		N/A
Coal sales	$	1,323,851	$	1,146,719	$	55.73	$	50.86
Operating expenses and outside coal purchases	$	864,501	$	762,479	$	36.39	$	33.82

Coal sales. Coal sales for the 2011 Period increased 15.4% to $1.3 billion from $1.1 billion for the 2010 Period. The increase of $177.1 million in coal sales reflected the benefit of higher average coal sales prices (contributing $115.6 million in coal sales) and increased tons sold (contributing $61.5 million in additional coal sales). Average coal sales prices increased $4.87 per ton sold to $55.73 per ton in the 2011 Period as compared to $50.86 per ton sold in the 2010 Period, primarily as a result of improved contract pricing across all regions as well as increased pricing of export market sales.

Operating expenses and outside coal purchases. Operating expenses and outside coal purchases increased 13.4% to $864.5 million for the 2011 Period from $762.5 million for the 2010 Period primarily due to increased coal sales, production volumes and outside coal purchases. On a per ton basis, operating expenses and outside coal purchases increased 7.6% to $36.39 per ton sold. Various significant factors related to the operating and outside coal purchases expense and per ton variances are discussed below:

•

Labor and benefit expenses per ton produced, excluding workers’ compensation, increased 8.6% to $11.71 per ton in the 2011 Period from $10.78 per ton in the 2010 Period. This increase of $0.93 per ton represents increased labor costs at our Illinois Basin and Mettiki mines and higher mine development labor and benefits at our Tunnel Ridge mine, partially offset by increased production at our River View, Pattiki and Central Appalachian mines;

•

Workers’ compensation expenses per ton produced decreased to $1.07 per ton in the 2011 Period from $1.10 per ton in the 2010 Period. The decrease of $0.03 per ton produced resulted primarily from unfavorable reserve adjustments for claims incurred during the 2010 Period;

•

Material and supplies expenses per ton produced increased 15.6% to $11.93 per ton in the 2011 Period from $10.32 per ton in the 2010 Period. The increase of $1.61 per ton produced resulted from an increase in costs for certain products and services, primarily roof support (increase of $0.47 per ton), outside services and contract labor used in the mining process (increase of $0.39 per ton), power and fuel used in the mining process (increase of $0.27 per ton), certain safety related materials and supplies (increase of $0.18 per ton) and ventilation (increase of $0.14 per ton), in addition to the negative cost impact of heightened regulatory oversight;

•

Maintenance expenses per ton produced increased 14.9% to $4.09 per ton in the 2011 Period from $3.56 per ton in the 2010 Period. The increase of $0.53 per ton produced was primarily due to higher maintenance costs on continuous miners in the Illinois Basin and Northern Appalachian regions, increased longwall maintenance costs at our Mettiki mine and higher costs in other various categories;

•

Mine administration expenses increased $7.9 million for the 2011 Period compared to the 2010 Period, primarily due to increased regulatory costs, insurance costs and increased components expense associated with safety equipment sales by the Matrix Group. In addition, mine administration expenses increased during the 2011 Period due to costs incurred at Tunnel Ridge and Warrior related to reserve studies and mine planning activities;

•

Contract mining expenses increased $0.4 million for the 2011 Period compared to the 2010 Period. The increase primarily reflects increased production expenses from our existing contract mining operations in Northern Appalachia, offset in part by the closure of one third-party mining operation during July 2011;

•

Production taxes and royalties expenses (which were incurred as a percentage of coal sales prices and volumes) increased $0.32 per produced ton sold in the 2011 Period compared to the 2010 Period primarily as a result of increased average coal sales prices across all regions;

•

The operating expenses increases described above were partially offset in the 2011 Period by a 1.0 million reduction in tons sold from higher cost per ton beginning of the year coal inventory compared to the 2010 Period;

•

Operating expenses for the 2010 Period included $1.2 million related to the retirement of certain assets related to the failed vertical hoist conveyor system at our Pattiki mine. For more information on Pattiki, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 4. Pattiki Vertical Hoist Conveyor System Failure In 2010” of this Quarterly Report on Form 10-Q; and

•

Outside coal purchases increased to $29.5 million for the 2011 Period compared to $12.1 million in the 2010 Period. The increase of $17.4 million was primarily attributable to increased coal brokerage activity as well as Mettiki’s higher cost per ton of coal purchased.

General and administrative. General and administrative expenses for the 2011 Period increased to $38.7 million compared to $36.6 million in the 2010 Period. The increase of $2.1 million was primarily due to increases in salary expense and certain incentive compensation expenses, partially offset by lower contributions to certain industry and advocacy groups.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, Matrix Design and other outside services and administrative services revenue from affiliates. Other sales and operating revenues increased to $19.6 million for the 2011 Period from $19.1 million for the 2010 Period. The increase of $0.5 million was primarily attributable to increased freeze proofing sales.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $117.2 million for the 2011 Period from $109.6 million for the 2010 Period. The increase of $7.6 million was primarily attributable to additional depreciation expense associated with capital expenditures related to the expansion of our River View mine, infrastructure and equipment expenditures at our Dotiki mine and capital expenditures related to various infrastructure improvements and efficiency projects at other mining operations.

Interest expense. Interest expense, net of capitalized interest, increased to $27.2 million for the 2011 Period from $22.7 million for the 2010 Period. The increase of $4.5 million was principally attributable to increased interest expense resulting from our $300 million term loan, which was completed in the fourth quarter of 2010, partially offset by reduced interest expense from our August 2011 and 2010 principal repayments of $18.0 million on our original senior notes issued in 1999, each of which is discussed in more detail below under “–Debt Obligations.”

Income tax expense (benefit). The income tax benefit was $0.2 million for the 2011 Period compared to income tax expense of $1.6 million for the 2010 Period. Income taxes are primarily due to the operations of Matrix Design, which is owned by our subsidiary, Alliance Service, Inc. The income tax benefit was due to operating losses in the 2011 Period from our Matrix Design operation.

Segment Adjusted EBITDA. Our 2011 Period Segment Adjusted EBITDA increased $76.4 million, or 18.9%, to $480.3 million from the 2010 Period Segment Adjusted EBITDA of $403.9 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,
	2011			2010			Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	382,164		$	344,216		$	37,948		11.0	%
Central Appalachia		43,590			24,141			19,449		80.6	%
Northern Appalachia		49,602			29,892			19,710		65.9	%
Other and Corporate		4,982			5,701			(719	)	(12.6	)%
Elimination		—			—			—		—

Total Segment Adjusted EBITDA (2)	$	480,338		$	403,950		$	76,388		18.9	%


Tons sold
Illinois Basin		19,133			18,465			668		3.6	%
Central Appalachia		1,918			1,680			238		14.2	%
Northern Appalachia		2,420			2,368			52		2.2	%
Other and Corporate		283			32			251		(1	)
Elimination		—			—			—		—

Total tons sold		23,754			22,545			1,209		5.4	%


Coal sales
Illinois Basin	$	964,079		$	875,805		$	88,274		10.1	%
Central Appalachia		153,315			121,947			31,368		25.7	%
Northern Appalachia		190,803			147,066			43,737		29.7	%
Other and Corporate		15,654			1,901			13,753		(1	)
Elimination		—			—			—		—

Total coal sales	$	1,323,851		$	1,146,719		$	177,132		15.4	%


Other sales and operating revenues
Illinois Basin	$	1,376		$	1,038		$	338		32.6	%
Central Appalachia		123			114			9		7.9	%
Northern Appalachia		2,604			2,681			(77	)	(2.9	)%
Other and Corporate		27,680			32,149			(4,469	)	(13.9	)%
Elimination		(12,135	)		(16,886	)		4,751		28.1	%

Total other sales and operating revenues	$	19,648		$	19,096		$	552		2.9	%


Segment Adjusted EBITDA Expense
Illinois Basin	$	583,291		$	532,626		$	50,665		9.5	%
Central Appalachia		109,848			97,921			11,927		12.2	%
Northern Appalachia		143,804			119,855			23,949		20.0	%
Other and Corporate		38,353			28,349			10,004		35.3	%
Elimination		(12,135	)		(16,886	)		4,751		28.1	%

Total Segment Adjusted EBITDA Expense (3)	$	863,161		$	761,865		$	101,296		13.3	%

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

(2)

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

•

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 as 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.

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,
	2011			2010
Segment Adjusted EBITDA	$	480,338		$	403,950
General and administrative		(38,698	)		(36,633	)
Depreciation, depletion and amortization		(117,237	)		(109,560	)
Interest expense, net		(26,973	)		(22,521	)
Income tax (expense) benefit		221			(1,586	)

Net income	$	297,651		$	233,650

(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.

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,
	2011			2010
Segment Adjusted EBITDA Expense	$	863,161		$	761,865
Outside coal purchases		(29,495	)		(12,122	)
Other income		1,340			614

Operating expense (excluding depreciation, depletion and amortization)	$	835,006		$	750,357

Illinois Basin – Segment Adjusted EBITDA increased 11.0% to $382.1 million for the 2011 Period from $344.2 million for the 2010 Period. This increase of $37.9 million was primarily attributable to increased contract pricing reflecting a higher average sales price of $50.39 per ton sold for the 2011 Period compared to $47.43 per ton sold for the 2010 Period, as well as higher tons sold which increased 3.6% to 19.1 million tons in the 2011 Period. Coal sales increased 10.1% to $964.1 million in the 2011 Period compared to $875.8 million in the 2010 Period. The increase of $88.3 million primarily reflects the increase in average coal sales price discussed above and increased tons produced and sold from expansion of production capacity at our River View mine and resumption of full production at our Pattiki mine in the first quarter of 2011, offset partially by weather disruptions and difficult mining conditions affecting certain mining operations. Total Segment Adjusted EBITDA Expense for the 2011 Period increased 9.5% to $583.3 million from $532.6 million in the 2010 Period and increased $1.65 per ton sold to $30.49 from $28.84 per ton sold, primarily as a result of certain cost increases described above under consolidated operating expenses, as well as lower production at the Dotiki and Warrior mines due to difficult mining conditions and weather related disruptions at the Gibson North and Hopkins mines. These increases were partially offset by higher production at our River View and Pattiki mines in the 2011 Period and the impact on the 2010 Period of a $1.2 million loss on the retirement of certain assets related to the failed vertical hoist conveyor system at our Pattiki mine. For more information on Pattiki, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 4. Pattiki Vertical Hoist Conveyor System Failure In 2010” of this Quarterly Report on Form 10-Q.

Central Appalachia – Segment Adjusted EBITDA increased 80.6% to $43.6 million for the 2011 Period, compared to $24.1 million for the 2010 Period. The increase of $19.5 million was primarily attributable to increased tons sold, which increased 14.2% to 1.9 million tons sold in the 2011 Period, as well as improved contract pricing resulting in a higher average coal sales price of $79.93 per ton sold during the 2011 Period compared to $72.59 per ton sold for the 2010 Period. Total Segment Adjusted EBITDA Expense for the 2011 Period increased 12.2% to $109.8 million from $97.9 million in the 2010 Period, primarily as a result of certain cost increases described above under consolidated operating expenses, particularly the impact of increasingly stringent regulatory compliance. Although Segment Adjusted EBITDA Expense increased, Segment Adjusted EBITDA expense per ton decreased 1.8% to $57.26 per ton in the 2011 Period from $58.29 per ton in the 2010 Period primarily as a result of increased production at both Central Appalachian mines and particularly Pontiki, which added a fourth mining unit during the 2011 Period.

Northern Appalachia – Segment Adjusted EBITDA increased to $49.6 million for the 2011 Period, compared to $29.9 million for the 2010 Period. The increase of $19.7 million was primarily attributable to improved contract pricing in the export coal markets resulting in a higher average sales price of $78.86 per ton sold for the 2011 Period compared to $62.11 per ton sold for the 2010 Period.

Total Segment Adjusted EBITDA Expense for the 2011 Period increased 20.0% to $143.8 million from $119.9 million in the 2010 Period and increased $8.81 on a per ton sold basis to $59.43 from $50.62 per ton sold, primarily as a result of higher coal sales volumes, increased costs associated with coal purchased for sale, and lower coal recoveries due to adverse geologic conditions, as well as the other cost increases described above under consolidated operating expenses, including expenses related to our Tunnel Ridge mine development project.

Other and Corporate – Segment Adjusted EBITDA and other sales and operating revenues decreased $0.7 million and $4.5 million, respectively, in the 2011 Period compared to the 2010 Period. These decreases were primarily attributable to lower Matrix Group safety equipment sales. Segment Adjusted EBITDA Expense increased 35.3% to $38.4 million for the 2011 Period compared to $28.3 million for the 2010 Period, primarily due to increased component expenses and research costs associated with services revenue and safety equipment sales by the Matrix Group, partially offset by an increase in equity income from MAC during the 2011 Period and a loss associated with United Kingdom currency held during the 2010 Period.

Liquidity and Capital Resources

Liquidity

We have historically satisfied our working capital requirements and funded our capital expenditures and debt service obligations from cash generated from operations, cash provided by the issuance of debt or equity and borrowings under revolving credit facilities. We believe that current cash on hand, cash generated from operations, cash from borrowings under our current credit facility and cash provided from the issuance of debt or equity will be sufficient to meet our working capital requirements, anticipated capital expenditures, scheduled debt payments, commitments and distribution payments. Our ability to satisfy our obligations, commitments 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, 2010.

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. Our initial investment on the Transaction Date was $69.5 million and we expect to fund approximately $400.0 million to $525.0 million, including initial funding, over the next three to four years. We plan to utilize current cash balances, availability under our revolving credit facility and future cash flows from existing operations to fund our commitments to the White Oak project. For more information on the White Oak transactions, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 7. White Oak Transactions” of this Quarterly Report on Form 10-Q.

Cash Flows

Cash provided by operating activities was $432.3 million for the 2011 Period compared to $394.2 million for the 2010 Period. The increase in cash provided by operating activities was principally attributable to higher net income, an increase in the change in accounts payable in the 2011 Period compared to the 2010 Period and a decrease in the change in accounts receivable in the 2011 Period compared to the 2010 Period. These increases in cash provided by operating activities were partially offset by an increase in coal inventory during the 2011 Period as compared to a significant decrease during the 2010 Period.

Net cash used in investing activities was $284.1 million for the 2011 Period compared to $238.1 million for the 2010 Period. The increase in cash used for investing activities was primarily attributable to our funding of investments related to the White Oak transactions during the 2011 Period, partially offset by decreases in capital expenditures at Tunnel Ridge as a result of our construction timetable and River View due to the addition of mining units during the 2010 Period and timing differences in accounts payable and accrued liabilities compared to the 2010 Period.

Net cash used in financing activities was $180.7 million for the 2011 Period compared to $157.1 million for the 2010 Period. The increase in cash used in financing activities was primarily attributable to increased distributions paid to partners in the 2011 Period.

Capital Expenditures

Capital expenditures decreased to $216.3 million in the 2011 Period from $233.8 million in the 2010 Period. See “—Cash Flows” above for additional information regarding capital expenditures.

Our anticipated total capital expenditures for the year ending December 31, 2011 are estimated in a range of $420.0 to $475.0 million, which also includes the acquisition of coal reserves from White Oak. Management anticipates funding remaining 2011 capital requirements with cash and cash equivalents ($307.2 million as of September 30, 2011), cash flows provided by operations and borrowing available under the ARLP Credit Facility, as discussed below. 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

ARLP Credit Facility. Our Intermediate Partnership maintains the ARLP Credit Facility, a $142.5 million revolving credit facility that matures September 25, 2012. The ARLP Credit Facility limits our annual capital expenditures, excluding acquisitions. The capital expenditure limit is $531.9 million for 2011 and $250.0 million for 2012. The amount of any annual limit in excess of actual capital expenditures for that year carries forward and is added to the annual limit for the subsequent year.

At September 30, 2011, we had $11.6 million of letters of credit outstanding with $130.9 million available for borrowing under the ARLP Credit Facility. We had no borrowings outstanding under the ARLP Credit Facility as of September 30, 2011 or December 31, 2010. We utilize the ARLP Credit Facility, as appropriate, to meet working capital requirements, anticipated capital expenditures, scheduled debt payments or distribution payments. We incur an annual commitment fee of 0.375% on the undrawn portion of the ARLP Credit Facility.

Senior Notes. Our Intermediate Partnership has $54.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in three remaining equal annual installments of $18.0 million 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.

Term Loan. On December 29, 2010, our Intermediate Partnership entered into a term loan agreement (the “Term Loan Agreement”) with various financial institutions for a term loan (the “Term Loan”) in the aggregate principal amount of $300 million. The Term Loan bears interest at a variable rate plus an applicable margin which fluctuates depending upon whether we elect the Term Loan (or a portion thereof) to bear interest at the Base Rate or the Eurodollar Rate (as defined in the Term Loan Agreement). We have elected the Eurodollar Rate which, with applicable margin, was 2.25% as of September 30, 2011. Interest is payable quarterly with principal due as follows: $15 million due per quarter beginning March 31, 2013 through December 31, 2013, $18.75 million due per quarter beginning March 31, 2014 through September 30, 2015 and the balance of $108.75 million due on December 31, 2015. 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 Term Loan Agreement. Upon a “change of control” (as defined in the Term Loan Agreement), the unpaid principal amount of the Term Loan, all interest thereon and all other amounts payable under the Term Loan Agreement will become due and payable.

The ARLP Credit Facility, Senior Notes, 2008 Senior Notes and the Term Loan (collectively, “ARLP Debt Arrangements”) are guaranteed by all of the 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 the following: (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 4.0 to 1.0, in both cases, during the four most recently ended fiscal quarters. The ARLP Credit Facility, Senior Notes and the 2008 Senior Notes limit our Intermediate Partnership’s maximum annual capital expenditures, excluding acquisitions, as described above. The debt to cash flow ratio and cash flow to interest expense ratio were 1.23 to 1.0 and 16.5 to 1.0, respectively, for the trailing twelve months ended September 30, 2011. Actual capital expenditures were $216.3 million for the 2011 Period. We were in compliance with the covenants of the ARLP Debt Arrangements as of September 30, 2011.

Other. In addition to the letters of credit available under the ARLP 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, 2011, we had $30.7 million in letters of credit outstanding under agreements with these two banks. SGP previously guaranteed $5.0 million of these outstanding letters of credit. On May 4, 2011, the ARLP Partnership entered into the Amendment and Restatement of Letter of Credit Facility Agreement, dated as of October 2, 2010, which released SGP from its guarantee of these outstanding letters of credit.

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, a time sharing agreement concerning use of aircraft and mineral and equipment leases with SGP and its affiliates. On October 27, 2011 the MGP board of directors and conflicts committee approved our purchase from SGP Land, LLC of two aircraft, which we expect to complete prior to the end of 2011. We also had guarantees from SGP for certain letters of credit. However, these guarantees were released on May 4, 2011.

On the Transaction Date, we entered into a series of transactions with 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 containing certain distribution and liquidation preferences, the acquisition and leaseback of certain reserves and surface rights, a coal handling and services agreement and a backstop equipment financing facility. For more information on the White Oak transactions, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 7. White Oak Transactions” of this Quarterly Report on Form 10-Q.

Please read our Annual Report on Form 10-K for the year ended December 31, 2010, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Related-Party Transactions” for additional information concerning related-party transactions.

New Accounting Standards

New Accounting Standards Issued and Adopted

New Accounting Standards Issued and Not Yet Adopted

periods within those years, beginning after December 15, 2011, and its provisions must be applied retrospectively for all periods presented in the financial statements. We do not anticipate the adoption of ASU 2011-05 on January 1, 2012 will have a material impact on our consolidated financial statements.

Other

Health Care Reform

On March 23, 2010, President Obama signed into law the Patient Protection and Affordable Care Act (“PPACA”). Additionally, on March 30, 2010, President Obama signed into law a reconciliation measure, the Health Care and Education Reconciliation Act of 2010. Implementation of the PPACA and the Health Care and Education Reconciliation Act (collectively, the “Health Care Act”) will result in comprehensive changes to health care in the U.S. Implementation of this legislation is planned to occur in phases, with standard plan changes taking effect beginning in 2010, but to a greater extent with the 2011 benefit plan year and extending through 2018.

The Health Care Act continues to have implications on benefit plan eligibility, coverage requirements and benefit standards and limitations. In the long term, our plan’s health care costs are expected to increase for various reasons due to the Health Care Act, including the potential impact of an excise tax on “high cost” plans (beginning in 2018), among other standard requirements. We anticipate that certain government agencies will provide additional regulations or interpretations concerning the application of the Health Care Act and reporting required thereunder. Until these regulations or interpretations are published, we are unable to reasonably estimate the further impact of such federal mandate requirements on our future health care costs.

The Health Care Act amended previous legislation related to coal workers’ pneumoconiosis, or black lung, providing automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims. The impact of these changes to our current population of beneficiaries and claimants resulted in an estimated $8.3 million increase to our black lung obligation at December 31, 2010. This increase to our obligation excludes the impact of potential re-filing of closed claims and potential filing rates for employees who terminated more than seven years ago as we do not have sufficient information to determine what, if any, claims will be filed until regulations are issued. The issuance of these regulations is currently uncertain and may take place over the next several years.

We will continue to evaluate the potential impact of the Health Care Act on our self-insured long term disability plan, black lung liabilities, results of operations and internal controls as governmental agencies issue interpretations regarding the meaning and scope of the Health Care Act. However, we believe it is likely that our costs will continue to increase as a result of these provisions, which may have an adverse impact on our results of operations and cash flows.

The Dodd–Frank Act

On July 21, 2010, President Obama signed into law the Dodd—Frank Wall Street Reform and Consumer Protection Act (“Dodd—Frank Act”). The additional regulations imposed by the Dodd—Frank Act on financial institutions may result in increased costs associated with future borrowings and decreased availability of credit. However, we are presently unable to determine the significance of any potential increase in our borrowing costs or potential liquidity constraints, if any. The Dodd—Frank Act also requires public mining companies to report certain safety information regarding citations, penalties and pending legal actions in each periodic report filed with the U.S. Securities and Exchange Commission (“SEC”) and to file current reports on Form 8-K for certain safety matters. We are continuing to evaluate the effect of the Dodd—Frank Act on our operations.

Pattiki Vertical Hoist Conveyor System Failure In 2010

While the Pattiki mine was temporarily idled, we expanded coal production at our other coal mines in the region, including the addition of the seventh and eighth production units at the River View mine, to partially offset the loss of production from the Pattiki mine. Consequently, the temporary idling of the Pattiki mine did not have a material adverse impact on our results of operations and cash flows. On July 19, 2010, the Pattiki mine resumed limited production while White County Coal continued to assess the effectiveness and reliability of the repaired vertical hoist conveyor system. On January 3, 2011, the Pattiki mine returned to full production.

Insurance

During September 2011, we completed our annual property and casualty insurance renewal with various insurance coverages effective October 1, 2011. 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-day waiting period for underground business interruption 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 supplies that are used directly or indirectly in the normal course of coal production such as diesel fuel, steel, explosives 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 each customer’s creditworthiness 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 prepayments 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 ARLP Credit Facility and Term Loan Agreement 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 no borrowings under the ARLP Credit Facility and $300.0 million outstanding under the Term Loan Agreement at September 30, 2011. A one percentage point increase in the interest rates related to the Term Loan Agreement would result in an annualized increase in 2011 interest expense of $3.0 million, based on borrowing levels at September 30, 2011. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a decrease of approximately $17.6 million in the estimated fair value of these borrowings.

As of September 30, 2011, the estimated fair value of the ARLP Debt Arrangements was approximately $741.5 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, 2011. 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, 2010.

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 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 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 Securities Exchange Act) as of September 30, 2011. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective as of September 30, 2011.

During the quarterly period ended September 30, 2011, there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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;

•

the impact of recent health care legislation;

•

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 due to labor and transportation costs and disruptions, equipment availability, governmental regulations, including those related to carbon dioxide emissions, and other factors;

•

legislation, regulatory and court decisions and interpretations thereof, including issues related to climate change and miner health and safety;

•

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;

•

greater than expected environmental regulation, costs and liabilities;

•

a variety of operational, geologic, permitting, labor and weather-related 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 alternative sources of energy, 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 credits;

•

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

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, 2010.

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, 2010 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.

RESERVED

ITEM 5.

OTHER INFORMATION

Federal Mine Safety and Health Act Information

Workplace safety is fundamental to our culture. Our operating subsidiaries empower their employees to be actively involved in continuous efforts to prevent accidents. By providing a work environment that rewards safety and encourages employee participation in the safety process, our mining operations strive to be the leaders in safety performance in our industry.

We are also a leader in developing and implementing new technologies to improve safety throughout the industry. For example, our subsidiary Matrix Design has developed two innovative technologies designed to improve safety in underground mining operations – a portable, wireless communication and electronic tracking system designed to allow surface personnel the ability to communicate with and locate underground mining personnel and a proximity detection system designed to improve the safety of continuous mining units used in underground operations. Matrix Design has completed installation of its communication and tracking system at all of our operating subsidiaries and has either installed or received orders to install this vital safety system at over half of the operating underground coal mines in the U.S. In addition, Matrix Design has thirty-four of its proximity detection systems functioning on continuous miners in our operating subsidiaries’ underground coal mines.

Our industry is focused on improving employee safety and its safety performance is continuously monitored, including through the mining industry standard of “non-fatal days lost”, or “NFDL”, which reflects both the frequency and severity of injuries incurred and, we believe, is a better measure of safety performance than compliance statistics. As indicated in the chart below, these efforts have resulted in significant safety improvements as the industry average NFDL as of the second quarter of 2011, as reported^(a) by the Mine Safety and Health Administration (“MSHA”), has decreased approximately 64% since 1998.

LOGO

(a)

Data compiled for all U.S. underground bituminous coal mines and related surface facilities from the MSHA report “Mine Injury and Worktime, Quarterly Closeout Edition.” Data for 1998 through 2010 reflects the “January – December, Final” report for each year. Data for 2011 reflects the “January – June, Preliminary” report for the first six months of 2011.

During this same time period, the combined NFDL rating of our operating subsidiaries has averaged approximately one-third better than the industry average and in 2010 we achieved the best overall annual NFDL rating in our history.

Our mining operations are subject to extensive and stringent compliance standards established pursuant to the Federal Mine Safety and Health Act of 1977, as amended by the MINER Act (as amended, the “Mine Act”). MSHA monitors and rigorously enforces compliance with these standards, and our mining operations are inspected frequently. During the three months ended September 30, 2011, our mines were subject to 1,586 MSHA inspection days with an average of only 0.25 “significant and substantial”, or “S&S”, citations written per inspection day.

We endeavor to comply at all times with all Mine Act regulations. However, the Mine Act has been construed as authorizing MSHA to issue citations and orders pursuant to the legal doctrine of strict liability, or liability without fault. If, in the opinion of an MSHA inspector, a condition exists that violates the Mine Act or regulations promulgated thereunder, then a citation or order will be issued regardless of whether we had any knowledge of, or fault in, the existence of that condition. Many of the Mine Act standards include one or more subjective elements, so that issuance of a citation often depends on the opinions or experience of the MSHA inspector involved and the frequency of citations will vary from inspector to inspector.

The number of citations issued also is affected by the size of the mine, in that the number of citations issued generally increases with the size of the mine. Our mines typically are larger in scale than most underground coal mines in the U.S. in terms of area, production and employee hours.

We take all allegations of violations of Mine Act standards seriously, and if we disagree with the assertions of an MSHA inspector, we exercise our right to challenge those findings by “contesting” the citation or order pursuant to the procedures established by the Mine Act and its regulations. During the three months ended September 30, 2011, our operating subsidiaries contested approximately 20% of all citations and the majority of S&S citations issued by MSHA inspectors. These contested proceedings frequently result in the dismissal or modification of previously issued citations, substantial reductions in the penalty amounts originally assessed by MSHA, or both.

The Dodd—Frank Act requires issuers to include in periodic reports filed with the SEC certain information relating to citations or orders for violations of standards under the Mine Act. Responding to that legislation, we report that, for the three months ended September 30, 2011, none of our operating subsidiaries (a) received any violations under section 110(b)(2) of the Mine Act for failure to make reasonable efforts to eliminate a known violation of a mandatory safety or health standard that substantially proximately caused, or reasonably could have been expected to cause, death or serious bodily injury, (b) received any MSHA written notice under Mine Act section 104(e) of a pattern of violations of mandatory health or safety standards or the potential to have such a pattern, or (c) had any fatalities. Webster County Coal, LLC, has one (1) legal proceeding pending before the Federal Mine Safety and Health Review Commission (“Commission”), which seeks an appeal of an administrative law judge’s decision in three consolidated cases involving Webster County Coal, LLC. We have contests of 229 citations or orders pending before the administrative law judges of the Commission that were initiated during the three months ended September 30, 2011 and that involve all types of citations (i.e., not only S&S citations).

The following table sets out additional information required by the Dodd—Frank Act for the three months ended September 30, 2011. The mine data retrieval system maintained by MSHA may show information that is different than what is provided herein. Any such difference may be attributed to the need to update that information on MSHA’s system or other factors.


Subsidiary Name ⁽¹⁾	Section 104(a) Citations⁽²⁾		Section 104(b) Orders ⁽³⁾		Section 104(d) Citations and Orders ⁽⁴⁾		Section 107(a) Orders ⁽⁵⁾		Total Proposed Assessments (in thousands) ⁽⁶⁾
*Illinois Basin Operations*
Webster County Coal, LLC (KY)		79		—		—		—	$	83.0
Warrior Coal, LLC (KY)		63		1		—		—	$	132.0
Hopkins County Coal, LLC (KY)		22		—		4		—	$	9.0
River View Coal, LLC (KY)		44		—		3		—	$	16.0
White County Coal, LLC (IL)		21		—		1		—	$	4.0
Gibson County Coal, LLC (IN)		34		—		—		—	$	37.0

*Central Appalachian Operations*
Pontiki Coal, LLC (KY)		56		1		—		2	$	54.0
MC Mining, LLC (KY)		27		—		—		—	$	26.0

*Northern Appalachian Operations*
Mettiki Coal, LLC (MD)		1		—		—		—	$	—
Mettiki Coal (WV), LLC		23		—		2		—	$	25.0
Tunnel Ridge, LLC (PA/WV)		16		—		1		—	$	3.0

(1)

The statistics reported for each of our subsidiaries listed above include all components of the mining complex involved and therefore may involve multiple MSHA identification numbers. Any S&S citations or orders issued to our subsidiary, Excel Mining, LLC, are included in the statistics for either Pontiki or MC Mining, depending on the mining complex involved.

(2)	Mine Act section 104(a) citations shown above are for alleged violations of health or safety standards that could significantly and substantially contribute to a serious injury.

(3)	Mine Act section 104(b) orders are for alleged failures to totally abate a citation within the period of time specified in the citation.

(4)	Mine Act section 104(d) citations and orders are for an alleged unwarrantable failure (i.e. aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.

(5)	Mine Act section 107(a) orders are for alleged conditions or practices which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated and result in orders of immediate withdrawal from the area of the mine affected by the condition.

(6)	Amounts shown include assessments proposed by MSHA during the three months ended September 30, 2011 on the citations and orders reflected in this chart.

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 8, 2011, 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 8, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

32.2

101

Interactive Data File (Form 10-Q for the quarter ended September 30, 2011 furnished in XBRL). The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed” and, in accordance with Rule 406T of Regulation S-T, is not deemed “filed” or part of a registration statement or prospectus for purposes of Sections 11 and 12 of the Securities Act of 1933, as amended, and Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under these sections.

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

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 8, 2011.


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