UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2009

OR

¨ 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    ¨  Yes    ¨  No

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

Large Accelerated Filer	x	Accelerated Filer	¨
Non-Accelerated Filer	¨  (Do not check if a smaller reporting company)	Smaller Reporting Company	¨

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

As of August 7, 2009, 36,661,029 Common Units are outstanding.

TABLE OF CONTENTS

PART I
FINANCIAL INFORMATION
		Page
ITEM 1.	Financial Statements (Unaudited)	1
	Alliance Resource Partners, L.P. and Subsidiaries
	Condensed Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008	1
	Condensed Consolidated Statements of Income for the three and six months ended June 30, 2009 and 2008	2
	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008	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.	Submission of Matters to a Vote of Security Holders	40
ITEM 5.	Other Information	40
ITEM 6.	Exhibits	40

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PART I

FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)

	June 30, 2009			December 31, 2008
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	157,413		$	244,875
Trade receivables		88,439			87,922
Other receivables		4,477			6,018
Due from affiliates		145			—
Marketable securities		5,094			—
Inventories		49,837			26,510
Advance royalties		3,200			3,200
Prepaid expenses and other assets		3,815			10,070
Total current assets		312,420			378,595
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost		1,241,812			1,085,214
Less accumulated depreciation, depletion and amortization		(506,125	)		(468,784	)
Total property, plant and equipment, net		735,687			616,430
OTHER ASSETS:
Advance royalties		26,680			23,828
Other long-term assets		10,517			11,787
Total other assets		37,197			35,615
TOTAL ASSETS	$	1,085,304		$	1,030,640
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	71,931		$	63,236
Due to affiliates		44			706
Accrued taxes other than income taxes		12,009			11,195
Accrued payroll and related expenses		19,517			20,555
Accrued interest		3,451			3,454
Workers’ compensation and pneumoconiosis benefits		9,429			9,377
Current capital lease obligation		338			351
Other current liabilities		13,961			11,911
Current maturities, long-term debt		18,000			18,000
Total current liabilities		148,680			138,785
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities		440,000			440,000
Pneumoconiosis benefits		32,819			31,436
Accrued pension benefit		20,823			19,952
Workers’ compensation		54,187			47,828
Asset retirement obligations		57,376			56,204
Due to affiliates		688			420
Long-term capital lease obligation		624			784
Other liabilities		4,850			5,039
Total long-term liabilities		611,367			601,663
Total liabilities		760,047			740,448
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
Alliance Resource Partners, L.P. (“ARLP”) Partners’ Capital:
Limited Partners - Common Unitholders 36,661,029 and 36,613,458 units outstanding, respectively		636,840			604,998
General Partners’ deficit		(294,068	)		(295,834	)
Accumulated other comprehensive income (loss)		(18,621	)		(19,899	)
Total ARLP Partners’ Capital		324,151			289,265
Noncontrolling interest		1,106			927
Total Partners’ Capital		325,257			290,192
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,085,304		$	1,030,640

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except unit and per unit data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
SALES AND OPERATING REVENUES:
Coal sales	$	287,620		$	261,567		$	599,880		$	530,725
Transportation revenues		12,794			11,007			23,684			21,627
Other sales and operating revenues		3,490			3,650			9,640			7,460
Total revenues		303,904			276,224			633,204			559,812
EXPENSES:
Operating expenses (excluding depreciation, depletion and amortization)		204,477			191,363			400,853			383,981
Transportation expenses		12,794			11,007			23,684			21,627
Outside coal purchases		432			4,552			5,192			7,455
General and administrative		9,307			12,119			19,041			20,950
Depreciation, depletion and amortization		28,272			25,600			55,622			48,894
Gain from sale of coal reserves		—			(5,159	)		—			(5,159	)
Net gain from insurance settlement and other		—			(2,790	)		—			(2,790	)
Total operating expenses		255,282			236,692			504,392			474,958
INCOME FROM OPERATIONS		48,622			39,532			128,812			84,854
Interest expense (net of interest capitalized for the three and six months ended June 30 , 2009 and 2008 of $332, $80, $547 and $302, respectively)		(7,808	)		(3,250	)		(15,789	)		(6,238	)
Interest income		293			197			924			295
Other income		202			250			428			467
INCOME BEFORE INCOME TAXES		41,309			36,729			114,375			79,378
INCOME TAX EXPENSE (BENEFIT)		(201	)		(70	)		225			(725	)
NET INCOME		41,510			36,799			114,150			80,103
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		(50	)		(102	)		(179	)		(243	)
NET INCOME ATTRIBUTABLE TO ALLIANCE RESOURCE PARTNERS, L.P. (“NET INCOME OF ARLP”)	$	41,460		$	36,697		$	113,971		$	79,860
GENERAL PARTNERS’ INTEREST IN NET INCOME OF ARLP	$	14,764		$	11,663		$	29,621		$	20,819
LIMITED PARTNERS’ INTEREST IN NET INCOME OF ARLP	$	26,696		$	25,034		$	84,350		$	59,041
BASIC AND DILUTED NET INCOME OF ARLP PER LIMITED PARTNER UNIT (Note 6)	$	0.72		$	0.68		$	2.28		$	1.60
DISTRIBUTIONS PAID PER LIMITED PARTNER UNIT	$	0.73		$	0.585		$	1.445		$	1.17
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-BASIC		36,993,874			36,868,173			36,996,451			36,862,448
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-DILUTED		36,993,874			36,868,173			36,996,451			36,881,752

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended June 30,
	2009			2008
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	164,261		$	150,799
CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(174,685	)		(70,950	)
Changes in accounts payable and accrued liabilities		8,364			3,356
Proceeds from sale of property, plant and equipment		1			567
Proceeds from sale of coal reserves		—			7,159
Purchase of marketable securities		(4,527	)		—
Payment for acquisition of coal reserves and other assets		—			(13,300	)
Receipts of prior advances on Gibson rail project		1,223			1,023
Net cash used in investing activities		(169,624	)		(72,145	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		—			350,000
Borrowings under revolving credit facilities		—			88,850
Payments under revolving credit facilities		—			(95,350	)
Payments on capital lease obligation		(173	)		(185	)
Payment of debt issuance costs		—			(830	)
Net settlement of employee withholding taxes on vesting of Long-Term Incentive Plan		(791	)		—
Cash contributions by General Partners		31			50
Distributions paid to Partners		(81,353	)		(60,933	)
Net cash provided by (used in) financing activities		(82,286	)		281,602
EFFECT OF CURRENCY TRANSLATION ON CASH		187			—
NET CHANGE IN CASH AND CASH EQUIVALENTS		(87,462	)		360,256
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		244,875			1,118
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	157,413		$	361,374
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	16,126		$	6,199
NON-CASH INVESTING AND FINANCING ACTIVITY:
Accounts payable for purchase of property, plant and equipment	$	23,456		$	8,402
Market value of common units vested in Long-Term Incentive Plan before minimum statutory tax withholding requirements	$	2,333		$	3,658

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND PRESENTATION

Significant Relationships Referenced in Notes to Condensed Consolidated Financial Statements

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

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

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

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

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

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

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

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

Organization

ARLP is a Delaware limited partnership listed on the NASDAQ Global Select Market under the ticker symbol “ARLP.” ARLP was formed in May 1999, to acquire, upon completion of ARLP’s initial public offering on August 19, 1999, certain coal production and marketing assets of Alliance Resource Holdings, Inc., a Delaware corporation (“ARH”), consisting of substantially all of ARH’s operating subsidiaries, but excluding ARH. ARH 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.

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Basis of Presentation

The accompanying condensed consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of June 30, 2009 and December 31, 2008, results of our operations for the three and six months ended June 30, 2009 and 2008 and our cash flows for the six months ended June 30, 2009 and 2008. All of our intercompany transactions and accounts have been eliminated. Net income attributable to Alliance Resource Partners, L.P. from our accompanied condensed consolidated financial statements will be described as “Net Income of ARLP.”

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, 2008.

2. NEW ACCOUNTING STANDARDS

New Accounting Standards Issued and Adopted

In December 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 141R, Business Combinations. SFAS No. 141R applies to all business combinations and establishes guidance for recognizing and measuring identifiable assets acquired, liabilities assumed, noncontrolling interests in the acquiree and goodwill. Most of these items are recognized at their full fair value on the acquisition date, including acquisitions where the acquirer obtains control but less than 100% ownership in the acquiree. SFAS No. 141R also requires expensing restructuring and acquisition-related costs as incurred and establishes disclosure requirements to enable the evaluation of the nature and financial effects of the business combination. SFAS No. 141R is effective for business combinations with an acquisition date in fiscal years beginning after December 15, 2008. We did not complete any business acquisitions during the six months ended June 30, 2009.

We adopted the provisions of SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements (Note 11), Emerging Issues Task Force (“EITF”) No. 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings Per Share, to Master Limited Partnerships, and Financial Staff Position (“FSP”) No. EITF 03-6-1 (Note 6) on January 1, 2009.

We adopted FSP SFAS No. 107-1 and Accounting Principles Board (“APB”) Opinion No. 28-1, Interim Disclosures about Fair Value of Financial Instruments, beginning with the quarterly period ended June 30, 2009. FSP SFAS No. 107-1 and APB No. 28-1 amend SFAS No. 107, Disclosures about Fair Values of Financial Instruments, to require disclosures about fair value of financial instruments in interim financial statements as well as in annual financial statements. FSP SFAS No. 107-1 and APB No. 28-1 also amend APB Opinion No. 28, Interim Financial Reporting, to require those disclosures in all interim financial statements (Note 5).

We adopted SFAS No. 165, Subsequent Events, beginning with the quarterly period ended June 30, 2009. SFAS No. 165 establishes the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date, that is, whether that date represents the date the financial statements were issued or were available to be issued (Note 12).

5

New Accounting Standards Issued and Not Yet Adopted

In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles a replacement of FASB Statement No. 162, which is effective for interim periods ending after September 15, 2009. SFAS No. 168, establishes the FASB Accounting Standards Codification as the only source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. We will adopt the provisions of SFAS No. 168 beginning with the quarter ending September 30, 2009 and do not believe adoption of SFAS No. 168 will have a material impact on our consolidated financial statement disclosures.

In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R), which amends FASB Interpretation (“FIN”) No. 46(R), Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, and changes the consolidation guidance applicable to a variable interest entity (“VIE”). SFAS No. 167 also amends the guidance governing the determination of whether an enterprise is the primary beneficiary of a VIE, and is, therefore, required to consolidate an entity, by requiring a qualitative analysis rather than a quantitative analysis. The qualitative analysis will include, among other things, consideration of who has the power to direct the activities of the entity that most significantly impact the entity’s economic performance and who has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. This standard also requires continuous reassessments of whether an enterprise is the primary beneficiary of a VIE. Previously, FIN No. 46(R) required reconsideration of whether an enterprise was the primary beneficiary of a VIE only when specific events had occurred. Qualifying special purpose entities, which were previously exempt from the application of this standard, will be subject to the provisions of this standard when it becomes effective. SFAS No. 167 also requires enhanced disclosures about an enterprise’s involvement with a VIE. The provisions of SFAS No. 167 are effective as of the beginning of interim and annual reporting periods that begin after November 15, 2009. We are currently evaluating the requirements of SFAS No. 167.

In December 2008, the FASB issued FSP SFAS No. 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets. FSP SFAS No. 132(R)-1 amends SFAS No. 132(R), Employer’s Disclosures about Pensions and Other Postretirement Benefits, to require more detailed annual disclosures about employers’ plan assets, concentrations of risk within plan assets and valuation techniques used to measure the fair value of plan assets. The provisions of FSP SFAS No. 132(R)-1 are effective for fiscal years ending after December 15, 2009. We are currently evaluating the requirements of FSP SFAS No. 132(R)-1. However, we do not anticipate that the adoption of FSP SFAS No. 132(R)-1 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.

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At certain of our operations, property tax assessments for several years are under audit by various state tax authorities. We believe that we have recorded adequate liabilities based on reasonable estimates of any property tax assessments that may be ultimately assessed as a result of these audits.

4. ACQUISITIONS

On January 28, 2008, effective January 1, 2008, we acquired, through our subsidiary Alliance Resource Properties, LLC (“Alliance Resource Properties”), additional rights to approximately 48.2 million tons of coal reserves located in western Kentucky from SGP Land, LLC (“SGP Land”). SGP Land is a subsidiary of our special general partner and is indirectly owned by Mr. Craft. At the time of our acquisition, these reserves were leased by SGP Land to our subsidiaries, Webster County Coal, LLC (“Webster County Coal”), Warrior Coal, LLC (“Warrior”) and Hopkins County Coal, LLC (“Hopkins County Coal”) through mineral leases and sublease agreements, pursuant to which we had paid advance royalties of approximately $8.0 million that had not yet been recouped against production royalties. Those mineral leases and sublease agreements between SGP Land and our subsidiaries were assigned to Alliance Resource Properties by SGP Land in this transaction. The recoupable balances of advance minimum royalties and other payments at the time of this acquisition, other than $0.4 million paid to the base lessors, were eliminated upon consolidation of the Partnership’s financial statements. The purchase price of $13.3 million cash paid at closing was primarily attributable to the historical cost basis of the mineral rights included in property, plant and equipment. We financed this acquisition using a combination of existing cash on hand and borrowings under our revolving credit facility. Since this transaction was a related-party transaction, it was reviewed by the board of directors of our managing general partner (“Board of Directors”) and its conflicts committee (“Conflicts Committee”). Based upon these reviews, the Board of Directors and its Conflicts Committee approved the SGP Land transaction as fair and reasonable to us and our limited partners. Because the SGP Land acquisition was between entities under common control, it was accounted for at historical cost.

5. FAIR VALUE MEASUREMENTS

Effective January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements, 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. We elected to defer the application of SFAS No. 157 to nonfinancial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis until our fiscal year beginning January 1, 2009, as permitted by FSP No. SFAS 157-2. The application of SFAS No. 157 to nonfinancial assets and liabilities on January 1, 2009 did not have an impact on our condensed consolidated financial statements as of June 30, 2009.

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.

Our investment in marketable securities at June 30, 2009 that are classified as available for sale are comprised of a United Kingdom treasury bill with a six month maturity, which was valued using quoted prices in active markets that are considered Level 1 inputs. The fair value of our marketable securities at June 30, 2009 was $5.1 million and had a cumulative unrealized gain reflected in partners’ capital of $0.6 million at June 30, 2009.

7

We account for our workers’ compensation and long-term disability liabilities at fair value based on the estimated present value of current workers’ compensation and long-term disability benefits using our actuarial estimates. Our actuarial calculations are based on a blend of actuarial projection methods and numerous assumptions including development patterns, mortality, medical costs and interest rates and, therefore, are considered Level 3 inputs.

The following table provides a summary of changes in fair value of our Level 3 workers’ compensation and long-term disability liabilities (included in other current and long-term liabilities) for the three and six months ended June 30, 2009 and 2008, respectively (in thousands):

	Beginning Balance		Accruals Increase/Decrease		Payments		Interest Accretion	Valuation Changes (Gain)/ Loss		Ending Balance
Level 3 fair value summary for three months ended June 30, 2009:
Workers’ compensation liability	$	56,350	4,749		(2,625	)	864	3,744		$	63,082
Long-term disability liability	$	2,121	(404	)	(53	)	43	—		$	1,707
Level 3 fair value summary for three months ended June 30, 2008:
Workers’ compensation liability	$	53,056	4,019		(3,105	)	765	(492	)	$	54,243
Long-term disability liability	$	2,776	175		(55	)	46	(372	)	$	2,570
Level 3 fair value summary for six months ended June 30, 2009:
Workers’ compensation liability	$	56,671	9,147		(5,953	)	1,728	1,489		$	63,082
Long-term disability liability	$	2,485	(767	)	(97	)	86	—		$	1,707
Level 3 fair value summary for six months ended June 30, 2008:
Workers’ compensation liability	$	51,619	8,200		(5,929	)	1,530	(1,177	)	$	54,243
Long-term disability liability	$	2,791	175		(116	)	92	(372	)	$	2,570

Valuation changes gain/loss related to the workers’ compensation and the long-term disability liabilities primarily represent valuation changes attributable to changes in the estimated liability for benefits associated with prior years or due to changes in interest rates and are recorded in operating expenses in our condensed consolidated statement of income.

The carrying amounts for accounts receivable and accounts payable approximate fair value because of the short maturity of those instruments. At June 30, 2009 and December 31, 2008, the estimated fair value of our fixed rate term debt, including current maturities, was approximately $456.2 million and $362.8 million, respectively, based on interest rates that we believe are currently available to us for issuance of debt with similar terms and remaining maturities.

6. NET INCOME OF ARLP PER LIMITED PARTNER UNIT

On January 1, 2009, we adopted EITF No. 07-4, which considers whether the IDR of a master limited partnership represents a participating security when considered in the calculation of earnings per unit under the two-class method. The EITF also considers whether the partnership agreement contains

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any contractual limitations concerning distributions to IDR holders that would impact the amount of earnings to allocate to the IDR holders for each reporting period. If distributions are contractually limited to the IDR holders’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the IDR holders. We believe our partnership agreement contractually limits our distributions to available cash and therefore, undistributed earnings are no longer allocated to the IDR holder as provided under EITF No. 07-4. Accordingly, the adoption of EITF No. 07-4 impacts our presentation of earnings per unit in periods when Net Income of ARLP exceeds the aggregate distributions because undistributed earnings are no longer allocated to the IDR holder as previously prescribed under the provisions of EITF No. 03-6, Participating Securities and the Two-Class Method under FASB Statement No. 128, Earnings per Share.

Also, on January 1, 2009, we adopted the provisions of FASB FSP No. EITF No. 03-6-1 Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities. This FSP affects entities that accrue cash dividends on share-based payment awards during the awards’ service period when the dividends are not required to be returned if the employees forfeit the award. The FSP requires that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders and are considered participating securities. Because the awards are considered participating securities, the issuing entity is required to apply the two-class method of computing basic and diluted earnings per share. Based on the requirements of FSP No. EITF 03-6-1, we now include outstanding unvested awards under our Long-Term Incentive Plan (“LTIP”) (Note 7) in our calculation of basic weighted average limited partner units outstanding.

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The following is a reconciliation of Net Income of ARLP and weighted average units used in computing basic and diluted earnings per unit with retrospective application for the three and six months ended June 30, 2009 and 2008, respectively, (in thousands, except per unit data):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net Income of ARLP	$	41,460		$	36,697		$	113,971		$	79,860
Adjustments:
General partner’s priority distributions		(14,219	)		(11,152	)		(27,900	)		(19,614	)
General partners’ 2% equity ownership		(545	)		(511	)		(1,721	)		(1,205	)
Limited partners’ interest in Net Income of ARLP	$	26,696		$	25,034		$	84,350		$	59,041
Limited partner units outstanding		36,661			36,613			36,650			36,596
Non-vested LTIP units outstanding		333			255			346			266
Total weighed average units outstanding – basic		36,994			36,868			36,996			36,862
Basic Net Income of ARLP per limited partner unit	$	0.72		$	0.68		$	2.28		$	1.60
Weighted average limited partner units – basic		36,994			36,868			36,996			36,862
Dilutive units:
Directors’ compensation phantom units		—			—			—			6
Supplemental Executive Retirement Plan phantom units		—			—			—			14
Weighted average limited partner units, assuming dilutive effect of contingently issuable units		36,994			36,868			36,996			36,882
Diluted Net Income of ARLP per limited partner unit	$	0.72		$	0.68		$	2.28		$	1.60

Net Income of ARLP is allocated to the general partners and limited partners in accordance with their respective partnership percentages, after giving effect to any special income allocations, including incentive distributions to our managing general partner, the holder of the IDR, which are declared and paid following the close 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.

On January 29, 2008 the compensation committee of the Board of Directors (“Compensation Committee”) approved amendments to the Deferred Compensation Plan for Directors and Supplemental Executive Retirement Plan to eliminate the option of settling awards in common units of ARLP and require that vested benefits be paid to participants in cash only. As a result, the phantom units associated with these plans are no longer considered in the calculation of diluted units effective January 29, 2008, whereas the non-vested LTIP grants associated with the LTIP Plan continue to entitle the LTIP participants to receive ARLP common units and accordingly these units are included in the calculation of basic and diluted units.

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The effects of adopting EITF No. 07-4 and FSP No. EITF No. 03-6-1 are required to be applied retrospectively to all periods presented. The following is a reconciliation of basic and diluted Net Income of ARLP per limited partner unit as presented in the prior period for the three and six months ended June 30, 2008:

	Three Months Ended June 30, 2008		Six Months Ended June 30, 2008
Basic and diluted Net Income of ARLP per limited partners unit as previously reported under EITF No. 03-6	$	0.67	$	1.43
Effect of the adoption of EITF No. 07-4 on basic and diluted Net Income of ARLP per limited partner unit		0.01		0.18
Effect of the adoption of FSP No. EITF No. 03-6-1 on basic and diluted Net Income of ARLP per limited partner unit		—		(0.01	)
Basic and diluted Net Income of ARLP per limited partner unit as presented	$	0.68	$	1.60

7. COMPENSATION PLANS

We have the LTIP for certain employees of our managing general partner and its affiliates who perform services for us. The LTIP awards are grants of non-vested notional units, which upon satisfaction of vesting requirements entitle the LTIP participant to receive ARLP common units. On January 27, 2009, the Compensation Committee determined that the vesting requirements for the 2006 grants of 71,975 units (which is net of 18,725 forfeitures) had been satisfied as of January 1, 2009. As a result of this vesting, on February 12, 2009, we issued 47,571 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 29, 2008 and October 28, 2008, the Compensation Committee authorized additional grants up to 100,000 and 152,445 units, respectively of which 93,600 and 141,145 units had been granted as of December 31, 2008 and will vest January 1, 2011 and 2012, respectively subject to satisfaction of certain financial tests. During the six months ended June 30, 2009, LTIP grants were made of another 2,000 units from the October 28, 2008 authorization and of an additional 7,125 units authorized by the Compensation Committee on February 20, 2009, all of which will vest on January 1, 2012 subject to satisfaction of certain financial tests. The fair value of these 2009 grants is equal to the intrinsic value at the date of grant, which was $25.02 per unit on a weighted average basis. LTIP expense was $0.9 million, $0.8 million, $1.7 million and $1.5 million, for the three and six months ended June 30, 2009 and 2008, respectively. As of June 30, 2009, the outstanding unvested LTIP grants exceeded the units available for issuance under the LTIP by 1,705 units. However, “reloading” of units available for awards as a result of settlement of a portion of outstanding awards in cash to satisfy tax withholding obligations, as provided in the LTIP, will provide sufficient units to fulfill all outstanding awards.

As of June 30, 2009, there was $5.3 million in total unrecognized compensation expense related to the non-vested LTIP grants that are expected to vest. That expense is expected to be recognized over a weighted-average period of 1.7 years. As of June 30, 2009, the intrinsic value of the non-vested LTIP grants was $10.8 million. As of June 30, 2009, the total obligation associated with the LTIP was $4.9 million and is included in the partners’ capital-limited partners’ line item in our condensed consolidated balance sheets.

8. COMPONENTS OF PENSION PLAN NET PERIODIC BENEFIT COSTS

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. Effective during 2008, new employees of these participating operations are no longer eligible to participate in the Pension Plan, but are eligible to participate in a defined contribution profit sharing and savings plan (“PSSP”) that we sponsor. Additionally, certain employees participating in the Pension Plan,

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for some of those participating operations, had the one-time option during 2008 to remain in the Pension Plan or participate in enhanced benefit provisions under the PSSP. Components of the net periodic benefit cost for each of the periods presented are as follows (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Service cost	$	667		$	704		$	1,334		$	1,407
Interest cost		754			652			1,509			1,305
Expected return on plan assets		(608	)		(879	)		(1,216	)		(1,759	)
Amortization of actuarial loss		356			—			711			—
Net periodic benefit cost	$	1,169		$	477		$	2,338		$	953

We previously disclosed in our financial statements for the year ended December 31, 2008 that we expected to contribute $10.6 million to the Pension Plan in 2009 for the 2008 plan year. Based upon guidance recently issued by the Internal Revenue Service regarding determination of pension plan liabilities, we currently anticipate contributing $5.8 million to the Pension Plan in 2009 for the 2008 plan year. During the three and six months ended June 30, 2009, we made a quarterly contribution payment of $0.8 million for the 2009 plan year.

9. COMPREHENSIVE INCOME

Total comprehensive income for the three and six months ended June 30, 2009 and 2008, respectively (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net income	$	41,510		$	36,799		$	114,150		$	80,103
Other comprehensive income:
Unrealized gain on marketable securities		567			—			567			—
Pension (Note 8)		356			—			711			—
Total other comprehensive income		923			—			1,278			—
Total comprehensive income		42,433			36,799			115,428			80,103
Less comprehensive income attributable to noncontrolling interest		(50	)		(102	)		(179	)		(243	)
Comprehensive income attributable to ARLP	$	42,383		$	36,697		$	115,249		$	79,860

Comprehensive income differs from net income due to an unrealized gain on our available for sale marketable securities resulting from valuation changes and amortization of actuarial loss associated with the adoption of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132 (R).

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10. SEGMENT INFORMATION

We operate in the eastern United States as a producer and marketer of coal to major utilities and industrial users. We have four reportable segments: the Illinois Basin, Central Appalachia, Northern Appalachia and Other and Corporate. The first three segments correspond to the three major coal producing regions in the eastern U.S. Coal quality, coal seam height, mining and transportation methods and regulatory issues are similar within each of these three segments.

The Illinois Basin segment is comprised of Webster County Coal’s Dotiki mining complex, Gibson County Coal, LLC’s Gibson North mining complex, Hopkins County Coal’s Elk Creek mining complex, White County Coal, LLC’s (“White County Coal”) Pattiki mining complex, Warrior’s mining complex, the Gibson County Coal (South), LLC (“Gibson South”) property, certain properties of Alliance Resource Properties and a mining complex currently under construction at River View Coal, LLC. We are in the process of permitting the Gibson South property for future mine development.

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

The Northern Appalachian segment is comprised of Mettiki Coal, LLC’s mining complex, Mettiki Coal (WV) LLC’s Mountain View mining complex, two small third-party mining operations (one of which was idled in May 2009), a mining complex currently under construction at Tunnel Ridge, LLC and the Penn Ridge Coal, LLC (“Penn Ridge”) property. We are in the process of permitting the Penn Ridge property for future mine development.

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Other and Corporate includes marketing and administrative expenses, the Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) dock activities, coal brokerage activity, Mid-America Carbonates, LLC (“MAC”), Matrix Design Group, LLC (“Matrix Design”) and certain properties of Alliance Resource Properties. Segment results for the three and six months ended June 30, 2009 and 2008 are presented below:

	Illinois Basin		Central Appalachia		Northern Appalachia		Other and Corporate		Elimination (1)			Consolidated
	(in thousands)
Operating segment results for the three months ended June 30, 2009:
Total revenues (2)	$	227,766	$	42,335	$	31,171	$	8,129	$	(5,497	)	$	303,904
Segment Adjusted EBITDA Expense (3)		141,115		34,849		27,729		6,428		(5,414	)		204,707
Segment Adjusted EBITDA (4)		77,012		6,151		1,625		1,697		(82	)		86,403
Capital expenditures		74,920		2,687		10,029		1,452		—			89,088
Operating segment results for the three months ended June 30, 2008:
Total revenues (2)	$	176,642	$	52,729	$	44,441	$	5,175	$	(2,763	)	$	276,224
Segment Adjusted EBITDA Expense (3)		121,495		38,599		33,656		4,575		(2,660	)		195,665
Segment Adjusted EBITDA (4)		47,306		16,927		7,613		5,757		(102	)		77,501
Capital expenditures		30,788		1,868		3,195		1,050		—			36,901
Operating segment results for the six months ended June 30, 2009:
Total revenues (2)	$	458,313	$	96,338	$	70,857	$	17,941	$	(10,245	)	$	633,204
Segment Adjusted EBITDA Expense (3)		272,524		71,945		58,284		13,027		(10,163	)		405,617
Segment Adjusted EBITDA (4)		167,770		22,969		8,337		4,909		(82	)		203,903
Total assets		654,320		88,429		163,443		179,197		(85	)		1,085,304
Capital expenditures		132,404		7,710		32,321		2,250		—			174,685
Operating segment results for the six months ended June 30, 2008:
Total revenues (2)	$	368,555	$	102,062	$	84,753	$	9,120	$	(4,678	)	$	559,812
Segment Adjusted EBITDA Expense (3)		248,521		76,748		61,849		8,547		(4,696	)		390,969
Segment Adjusted EBITDA (4)		104,756		28,049		16,611		5,731		18			155,165
Total assets		472,581		93,437		130,805		376,715		(56	)		1,073,482
Capital expenditures (5)		59,991		3,918		5,664		1,377		—			70,950

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

(2) Revenues included in the Other and Corporate column are primarily attributable to Mt. Vernon transloading revenues, administrative service revenues from affiliates, Matrix Design revenues, MAC rock dust revenues and brokerage sales (three and six months ended June 30, 2009 only).

(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.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Segment Adjusted EBITDA Expense	$	204,707		$	195,665		$	405,617		$	390,969
Outside coal purchases		(432	)		(4,552	)		(5,192	)		(7,455	)
Other income		202			250			428			467
Operating expenses (excluding depreciation, depletion and amortization)	$	204,477		$	191,363		$	400,853		$	383,981

(4) Segment Adjusted EBITDA is defined as net income before net interest expense, income taxes, depreciation, depletion and amortization, net income attributable to noncontrolling interest and general and administrative expenses. Consolidated Segment Adjusted EBITDA is reconciled to net income and Net Income of ARLP below (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Segment Adjusted EBITDA	$	86,403		$	77,501		$	203,903		$	155,165
General and administrative		(9,307	)		(12,119	)		(19,041	)		(20,950	)
Depreciation, depletion and amortization		(28,272	)		(25,600	)		(55,622	)		(48,894	)
Interest expense, net		(7,515	)		(3,053	)		(14,865	)		(5,943	)
Income tax (expense) benefit		201			70			(225	)		725
Net income		41,510			36,799			114,150			80,103
Net income attributable to noncontrolling interest		(50	)		(102	)		(179	)		(243	)
Net Income of ARLP	$	41,460		$	36,697		$	113,971		$	79,860

(5) Capital expenditures for the six months ended June 30, 2008 do not include acquisition of coal reserves and other assets in the Illinois Basin of $13.3 million separately reported in our condensed consolidated statements of cash flows.

11. NONCONTROLLING INTEREST

On January 1, 2009, we adopted SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, which establishes accounting and reporting standards for noncontrolling ownership interests in subsidiaries. Noncontrolling ownership interest in consolidated subsidiaries is presented in the consolidated balance sheet within partners’ capital as a separate component from the parent’s equity. Consolidated net income now includes earnings attributable to both the parent and the noncontrolling interests. Earnings per unit is based on earnings attributable to only the parent company and did not change upon adoption of SFAS No. 160. SFAS No. 160 provides guidance on accounting for changes in the parent’s ownership interest in a subsidiary, including transactions where control is retained and where control is relinquished. SFAS No. 160 also requires additional disclosure of information related to amounts attributable to the parent for income from continuing operations, discontinued operations and extraordinary items and reconciliations of the parent and noncontrolling interests’ equity of a subsidiary. SFAS No. 160 is applied prospectively to transactions involving noncontrolling interests, including noncontrolling interests that arose prior to the effective date, as of the beginning of 2009, the year of adoption. However, the presentation of noncontrolling interests within partners’ capital and the inclusion of earnings attributable to the noncontrolling interests in consolidated net income requires retrospective application to all periods presented.

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The noncontrolling interest designated as MAC represents a 50% third-party interest in MAC. White County Coal entered into a limited liability company agreement with a third-party in 2006 to form MAC, which manufactures and sells rock dust. We consolidate MAC’s financial results in accordance with FIN No. 46R, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. Based on the guidance in FIN No. 46R, we concluded that MAC is a VIE and we are the primary beneficiary. Effective January 1, 2010, we will adopt the provisions of SFAS No. 167, and we are currently evaluating its impact, if any, on MAC (Note 2).

The following tables present the change in partners’ capital with retrospective application due to the adoption of SFAS No. 160 for the six months ended June 30, 2009 and 2008 (in thousands):

	Alliance Resource Partners, L.P.
	Limited Partners’ Capital			General Partners			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest		Total Partners’ Capital
January 1, 2009	$	604,998		$	(295,834	)	$	(19,899	)	$	927	$	290,192
Net income		84,350			29,621			—			179		114,150
Other comprehensive income		—			—			1,278			—		1,278
Vesting of Long-Term Incentive Plan		(791	)		—			—			—		(791	)
Common unit-based compensation under Long-Term Incentive Plan		1,750			—			—			—		1,750
General Partners contribution		—			31			—			—		31
Distributions on common unit-based compensation		(526	)		—			—			—		(526	)
Distribution paid to Partners		(52,941	)		(27,886	)		—			—		(80,827	)
Balance at June 30, 2009	$	636,840		$	(294,068	)	$	(18,621	)	$	1,106	$	325,257
	Alliance Resource Partners, L.P.
	Limited Partners’ Capital			General Partners			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest		Total Partners’ Capital
January 1, 2008	$	607,777		$	(290,669	)	$	109		$	507	$	317,724
Net income		59,041			20,819			—			243		80,103
Vesting of Long-Term Incentive Plan		(1,181	)		—			—			—		(1,181	)
Common unit-based compensation under Long-Term Incentive Plan		1,478			—			—			—		1,478
Common control acquisitions		—			(9,809	)		—			—		(9,809	)
General Partners contribution		—			50			—			—		50
Distributions on common unit-based compensation		(349	)		—			—			—		(349	)
Distribution paid to Partners		(42,801	)		(17,783	)		—			—		(60,584	)
Balance at June 30, 2008	$	623,965		$	(297,392	)	$	109		$	750	$	327,432

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12. SUBSEQUENT EVENTS

On July 28, 2009, we declared a quarterly distribution for the quarter ended June 30, 2009, of $0.745 per unit, totaling approximately $42.1 million (which includes our managing general partner’s incentive distributions), on all common units outstanding, payable on August 14, 2009 to all unitholders of record as of August 7, 2009.

Subsequent events have been evaluated through August 7, 2009, the issuance date of the financial statements.

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

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

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

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

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

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

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

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

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

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

Summary

We are a diversified producer and marketer of coal primarily to major U.S. utilities and industrial users. We began mining operations in 1971 and, since then, have grown through acquisitions and internal development to become what we believe to be the fifth largest coal producer in the eastern U.S. We operate eight mining complexes in Illinois, Indiana, Kentucky, Maryland and West Virginia. We are constructing two new mining complexes, one in Kentucky and one in West Virginia, and also operate a coal loading terminal on the Ohio River at Mt. Vernon, 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 segments correspond to the three major coal producing regions in the eastern U.S. Coal quality, coal seam height, mining and transportation methods and regulatory issues are similar within each of these three segments.

• Illinois Basin segment is comprised of 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 (“White County Coal”) Pattiki mine and Warrior Coal, LLC’s (“Warrior”) mining complex, the Gibson County Coal (South), LLC (“Gibson South”) property, certain properties of Alliance Resource Properties, LLC (“Alliance Resource Properties”) and a mining complex currently under construction at River View Coal, LLC (“River View”). We are in the process of permitting the Gibson South property for future mine development.

• Central Appalachian segment is comprised of Pontiki Coal, LLC’s and MC Mining, LLC’s mining complexes.

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• Northern Appalachian segment is comprised of Mettiki Coal, LLC’s mining complex, Mettiki Coal (WV) LLC’s Mountain View mining complex, two small third-party mining operations (one of which was idled in May 2009), a mining complex currently under construction at Tunnel Ridge, LLC (“Tunnel Ridge”) and the Penn Ridge Coal, LLC (“Penn Ridge”) property. We are in the process of permitting the Penn Ridge property for future mine development.

• Other and Corporate segment includes marketing and administrative expenses, the Mt. Vernon dock activities, coal brokerage activity, Mid-America Carbonates, LLC (“MAC”), Matrix Design Group, LLC (“Matrix Design”) and certain properties of Alliance Resource Properties.

Results of Operations

Comparison of our operating results for the three months ended June 30, 2009 (“2009 Quarter”) and June 30, 2008 (“2008 Quarter”) and the six months ended June 30, 2009 (“2009 Period”) and June 30, 2008 (“2008 Period”) is affected by the following significant items:

• Gain on sale of non-core coal reserves of $5.2 million in the 2008 Quarter;

• Gain of $1.9 million on settlement of claims relating to the 2005 failure of the vertical belt system (the “Vertical Belt Incident”) at our Pattiki mine in the 2008 Quarter recorded as a reduction to operating expenses. The 2008 Quarter gain resulted from a settlement reached with the third-party installer of the vertical belt system and represents a partial recovery of expenses incurred in 2005; and

• Gain of $2.8 million on settlement of claims against the third-party that provided security services at the time of the December 2004 MC Mining mine fire (“MC Mining Fire Incident”) was recognized in the 2008 Quarter.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008

We reported Net Income of ARLP of $41.5 million for the 2009 Quarter compared to $36.7 million for the 2008 Quarter. This increase of $4.8 million was principally due to improved contract pricing resulting in an average coal sales price of $46.04 per ton sold, as compared to $39.50 per ton sold for the 2008 Quarter. We had tons sold of 6.2 million and tons produced of 6.3 million for the 2009 Quarter compared to tons sold of 6.6 million and tons produced of 6.5 million in the 2008 Quarter. Increased operating expenses during the 2009 Quarter primarily reflect the increase in labor and labor-related expenses, as well as higher sales-related expenses, maintenance costs and other factors described below.

	Three Months Ended June 30,
	2009		2008		2009		2008
	(in thousands)				(per ton sold)
Tons sold		6,247		6,622		N/A		N/A
Tons produced		6,324		6,467		N/A		N/A
Coal sales	$	287,620	$	261,567	$	46.04	$	39.50
Operating expenses and outside coal purchases	$	204,909	$	195,915	$	32.80	$	29.59

Coal sales. Coal sales for the 2009 Quarter increased 10.0% to $287.6 million from $261.6 million for the 2008 Quarter. The increase of $26.0 million in coal sales reflected the benefit of higher average coal sales prices (contributing $40.8 million in additional coal sales) partially offset by lower

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sales volumes (reducing coal sales by $14.8 million). Average coal sales prices increased $6.54 per ton sold to $46.04 per ton in the 2009 Quarter as compared to the 2008 Quarter, primarily as a result of improved contract pricing in the Illinois Basin and Central Appalachian regions.

Operating expenses. Operating expenses increased 6.9% to $204.5 million for the 2009 Quarter from $191.4 million for the 2008 Quarter. Higher operating expenses of $13.1 million resulted from increases and decreases associated with the specific factors listed below:

• Labor and benefit expenses per ton produced, excluding workers’ compensation, increased to $11.55 per ton in the 2009 Quarter from $9.29 per ton in the 2008 Quarter. This increase of $2.26 per ton represents pay rate increases and higher benefit expenses, particularly increased health care costs and retirement expenses, and the impact of increased headcount as we continue to hire and train new employees for the River View and Tunnel Ridge mine development projects;

• Workers’ compensation expenses per ton produced increased to $1.73 per ton in the 2009 Quarter from $0.82 per ton in the 2008 Quarter. The increase of $0.91 per ton produced primarily reflected a non-cash charge during the 2009 Quarter that resulted from discount rate changes, which increased the accrued liabilities for the present value of estimated future claim payments;

• Material and supplies per ton produced decreased 2.3% to $9.56 per ton in the 2009 Quarter from $9.79 per ton in the 2008 Quarter. The decrease of $0.23 per ton produced resulted from decreased costs for certain products and services particularly roof bolts, outside services, mine transportation, seals, and fuel used in the mining process and offset in part by higher power costs and reduced product recovery, among other factors;

• Maintenance expenses per ton produced increased 22.5% to $3.92 per ton in the 2009 Quarter from $3.20 per ton in the 2008 Quarter. The increase of $0.72 per ton produced resulted from higher repair costs related to continuous miners, belt conveyor equipment and other equipment categories;

• Operating expenses decreased due to a 287,000 ton reduction in produced tons sold reflecting lower export and spot market demand;

• Expenses incurred during the 2009 Quarter related to our River View and Tunnel Ridge organic growth projects increased $2.8 million over the 2008 Quarter;

• Production taxes and royalties expenses (which were incurred as a percentage of coal sales and coal volumes) increased $1.5 million in the 2009 Quarter as compared to the 2008 Quarter primarily as a result of increased average coal sales prices, partially offset by reduced tons sold; and

• The 2008 Quarter operating expenses benefited from a $1.9 million gain on settlement of claims related to the Vertical Belt Incident at our Pattiki mine.

General and administrative. General and administrative expenses for the 2009 Quarter decreased to $9.3 million compared to $12.1 million in the 2008 Quarter. The decrease of $2.8 million was primarily due to lower incentive compensation expense, partially offset by higher salary and benefit costs primarily related to increased staffing levels.

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Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, products and services provided by MAC and Matrix Design, and other outside services and administrative services revenue from affiliates. Other sales and operating revenues decreased to $3.5 million for the 2009 Quarter from $3.7 million for the 2008 Quarter. The decrease of $0.2 million was primarily attributable to decreased revenues from MAC product sales and other outside services, partially offset by increased transloading revenues.

Outside coal purchases. Outside coal purchases decreased to $0.4 million for the 2009 Quarter compared to $4.6 million in the 2008 Quarter. The decrease of $4.1 million was primarily attributable to a decrease in outside coal purchases at our Central Appalachian and Northern Appalachian regions due to reduced demand in the spot and export coal markets.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $28.3 million for the 2009 Quarter from $25.6 million for the 2008 Quarter. The increase of $2.7 million was primarily attributable to additional depreciation expense associated with continuing capital expenditures related to infrastructure improvements, efficiency projects and expansion of production capacity.

Interest expense. Interest expense, net of capitalized interest increased to $7.8 million for the 2009 Quarter from $3.2 million for the 2008 Quarter. The increase of $4.6 million was principally attributable to increased interest expense resulting from the 2008 financing activities, partially offset by reduced interest expense resulting from our August 2008 principal repayment of $18.0 million on our original senior notes issued in 1999. The 2008 financing activities are discussed in more detail below under “–Debt Obligations.”

Interest income. Interest income of $0.3 million for the 2009 Quarter was comparable to $0.2 million for the 2008 Quarter.

Transportation revenues and expenses. Transportation revenues and expenses each increased to $12.8 million for the 2009 Quarter compared to $11.0 million for the 2008 Quarter. The increase of $1.8 million was primarily attributable to increased coal sales volumes for which we arranged the transportation compared to the 2008 Quarter, partially offset by a decrease in average transportation rates reflecting lower fuel costs. The cost of transportation services are passed through to our customers. Consequently, we do not realize any gain or loss on transportation revenues.

Income before income taxes. Income before income taxes increased 12.5% to $41.3 million for the 2009 Quarter compared to $36.7 million for the 2008 Quarter. The increase of $4.6 million reflects the impact of the changes in revenues and expenses described above.

Income tax expense (benefit). Income tax benefit increased to $0.2 million for the 2009 Quarter compared to $0.1 million for the 2008 Quarter. The income tax benefit for the 2009 and 2008 Quarters was primarily due to operating losses of Matrix Design, which is owned by our subsidiary, Alliance Services, Inc. (“ASI”).

Net income attributable to noncontrolling interest. The noncontrolling interest represents a 50% third-party interest in MAC. The third-party’s portion of MAC’s net income was $50,000 and $102,000 for the 2009 Quarter and the 2008 Quarter, respectively. For more information about MAC, please read “Item 1. Financial Statements (Unaudited) – Note 11. Noncontrolling Interest” of this Quarterly Report on Form 10-Q.

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Segment Adjusted EBITDA. Our 2009 Quarter Segment Adjusted EBITDA increased $8.9 million, or 11.5%, to $86.4 million from the 2008 Quarter Segment Adjusted EBITDA of $77.5 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are (in thousands):

	Three Months Ended June 30,						Increase/(Decrease)
	2009			2008
Segment Adjusted EBITDA
Illinois Basin	$	77,012		$	47,306		$	29,706		62.8	%
Central Appalachia		6,151			16,927			(10,776	)	(63.7	)%
Northern Appalachia		1,625			7,613			(5,988	)	(78.7	)%
Other and Corporate		1,697			5,757			(4,060	)	(70.5	)%
Elimination		(82	)		(102	)		20		(19.6	)%
Total Segment Adjusted EBITDA (2)	$	86,403		$	77,501		$	8,902		11.5	%
Tons sold
Illinois Basin		5,062			4,959			103		2.1	%
Central Appalachia		615			866			(251	)	(29.0	)%
Northern Appalachia		570			797			(227	)	(28.5	)%
Other and Corporate		—			—			—		—
Elimination		—			—			—		—
Total tons sold		6,247			6,622			(375	)	(5.7	)%
Coal sales
Illinois Basin	$	217,961		$	168,656		$	49,305		29.2	%
Central Appalachia		40,999			52,736			(11,737	)	(22.3	)%
Northern Appalachia		28,653			40,175			(11,522	)	(28.7	)%
Other and Corporate		7			—			7		(1	)
Elimination		—			—			—		—
Total coal sales	$	287,620		$	261,567		$	26,053		10.0	%
Other sales and operating revenues
Illinois Basin	$	167		$	145		$	22		15.2	%
Central Appalachia		—			—			—		—
Northern Appalachia		701			1,094			(393	)	(35.9	)%
Other and Corporate		8,118			5,174			2,944		56.9	%
Elimination		(5,496	)		(2,763	)		(2,733	)	(98.9	)%
Total other sales and operating revenues	$	3,490		$	3,650		$	(160	)	(4.4	)%
Segment Adjusted EBITDA Expense
Illinois Basin	$	141,115		$	121,495		$	19,620		16.1	%
Central Appalachia		34,849			38,599			(3,750	)	(9.7	)%
Northern Appalachia		27,729			33,656			(5,927	)	(17.6	)%
Other and Corporate		6,428			4,575			1,853		40.5	%
Elimination		(5,414	)		(2,660	)		(2,754	)	(1	)
Total Segment Adjusted EBITDA Expense (3)	$	204,707		$	195,665		$	9,042		4.6	%

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

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(2) Segment Adjusted EBITDA is defined as net income before net interest expense, income taxes, depreciation, depletion and amortization, net income attributable to noncontrolling interest and general and administrative expenses. Consolidated EBITDA 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 its 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 and Net Income of ARLP (in thousands):

	Three Months Ended June 30,
	2009			2008
Segment Adjusted EBITDA	$	86,403		$	77,501
General and administrative		(9,307	)		(12,119	)
Depreciation, depletion and amortization		(28,272	)		(25,600	)
Interest expense, net		(7,515	)		(3,053	)
Income tax (expense) benefit		201			70
Net income	$	41,510		$	36,799
Net income attributable to noncontrolling interest		(50	)		(102	)
Net Income of ARLP	$	41,460		$	36,697

(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. Segment Adjusted EBITDA Expense is used as a supplemental financial measure by our management to assess the operating performance of our segments. Segment Adjusted EBITDA Expense is a key component of EBITDA in addition to coal sales and other sales and operating revenues. The exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA Expense allows management to focus solely on the evaluation of segment operating performance as it primarily relates to our operating expenses. Outside coal purchases are included in Segment Adjusted EBITDA Expense because tons sold and coal sales include sales from outside coal purchases.

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The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to Operating expense (in thousands):

	Three Months Ended June 30,
	2009			2008
Segment Adjusted EBITDA Expense	$	204,707		$	195,665
Outside coal purchases		(432	)		(4,552	)
Other income		202			250
Operating expense (excluding depreciation, depletion and amortization)	$	204,477		$	191,363

Illinois Basin – Segment Adjusted EBITDA, as defined in reference (2) to the table above, increased 62.8% to $77.0 million in the 2009 Quarter from $47.3 million in the 2008 Quarter. The increase of $29.7 million was primarily attributable to improved contract pricing reflecting a higher average coal sales price of $43.06 per ton during the 2009 Quarter compared to $34.01 per ton for the 2008 Quarter and slightly higher coal sales volumes in the 2009 Quarter. Increased coal sales were partially offset by higher Segment Adjusted EBITDA Expense in the 2009 Quarter. Total Segment Adjusted EBITDA Expense, defined in reference (3) to the above table, for the 2009 Quarter increased 16.1% to $141.1 million from $121.5 million in the 2008 Quarter, primarily as a result of cost increases described above under consolidated operating expenses and costs associated with higher produced tons sold. In addition, the comparison is affected by the $1.9 million gain on settlement of claims related to the Pattiki Vertical Belt Incident in the 2008 Quarter. On a per ton sold basis, Segment Adjusted EBITDA Expense for the 2009 Quarter increased $3.38 to $27.88 per ton compared to the 2008 Quarter Segment Adjusted EBITDA Expense of $24.50 per ton.

Central Appalachia – Segment Adjusted EBITDA, as defined in reference (2) to the table above, decreased 63.7% to $6.1 million for the 2009 Quarter compared to $16.9 million in the 2008 Quarter. The decrease of $10.8 million was primarily the result of lower sales volumes due to weak coal demand in the spot market and higher expenses per ton during the 2009 Quarter, partially offset by improved contract pricing that resulted in an increase in the average coal sales price of $5.81 per ton to $66.70 per ton in the 2009 Quarter, compared to $60.89 per ton in the 2008 Quarter. Although Segment Adjusted EBITDA Expense for the 2009 Quarter decreased 9.7% to $34.8 million from $38.6 million in the 2008 Quarter primarily as a result of lower coal sales volumes, Segment Adjusted EBITDA Expense per ton sold during the 2009 Quarter increased $12.12 per ton sold to $56.69 as compared to $44.57 per ton sold in the 2008 Quarter (for a definition of Segment Adjusted EBITDA Expense, see reference (3) to the above table). The increase in Segment Adjusted EBITDA Expense per ton resulted in part from decreased coal production in response to lower spot market demand and lower productivity due to Pontiki’s transition from the depleted Pond Creek coal seam into the thinner Van Lear coal seam during the 2009 Quarter. In addition, on a per ton basis, higher Segment Adjusted EBITDA Expenses resulted from increased materials and supplies primarily related to lower product recoveries and cost increases described above under consolidated operating expenses. Segment Adjusted EBITDA in the 2008 Quarter benefited from the $2.8 million gain recognized on settlement of claims from the third-party that provided security services at the time of the MC Mining Fire Incident as discussed above under results of operations.

Northern Appalachia – Segment Adjusted EBITDA, as defined in reference (2) to the table above, decreased 78.7% to $1.6 million for the 2009 Quarter as compared to $7.6 million in the 2008 Quarter. This decrease of $6.0 million was primarily the result of lower sales volumes and higher Segment

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Adjusted EBITDA expense per ton sold in the 2009 Quarter of $48.63 per ton, an increase of $6.38 per ton compared to $42.25 per ton in the 2008 Quarter (for a definition of Segment Adjusted EBITDA Expense, see reference (3) to the above table). Increased Segment Adjusted EBITDA Expense per ton in the 2009 Quarter resulted primarily from lower production, which was impacted by a longwall move, an additional reduction in longwall run-days and a curtailment of third-party mining operations during the 2009 Quarter, as well as the other cost increases described above under consolidated operating expenses, including expenses incurred related to our Tunnel Ridge organic growth project. Lower production was primarily in response to weak demand in export and spot coal markets. Although Segment Adjusted EBITDA Expense per ton sold increased in the 2009 Quarter, Segment Adjusted EBITDA Expense for the 2009 Quarter decreased 17.6% to $27.7 million from $33.7 million in the 2008 Quarter, primarily as a result of lower coal sales offset in part by higher expenses per ton as described above.

Other and Corporate – Segment Adjusted EBITDA, as defined in reference (2) to the above table, decreased to $1.7 million in the 2009 Quarter from $5.8 million in the 2008 Quarter, primarily due to a $5.2 million gain on the sale of non-core reserves in the 2008 Quarter, partially offset by increased Matrix Design product sales and service revenues and Mt. Vernon transloading revenues. The increase in Segment Adjusted EBITDA Expense, as defined in reference (3) to the above table, primarily reflects increased expenses associated with higher outside services revenue and product sales.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

We reported record Net Income of ARLP of $114.0 million for the 2009 Period compared to $79.9 million for the 2008 Period. This increase of $34.1 million was principally due to improved contract pricing resulting in an average coal sales price of $47.33 per ton sold, as compared to $38.98 per ton sold for the 2008 Period. We had tons sold of 12.7 million and tons produced of 13.2 million for the 2009 Period compared to 13.6 million tons sold and 13.3 million tons produced for the 2008 Period. Increased operating expenses during the 2009 Period primarily reflect the increase in labor and labor-related expenses, as well as higher sale-related expenses, maintenance costs and other factors described below.

	Six Months Ended June 30,
	2009		2008		2009		2008
	(in thousands)				(per ton sold)
Tons sold		12,674		13,616		N/A		N/A
Tons produced		13,196		13,332		N/A		N/A
Coal sales	$	599,880	$	530,725	$	47.33	$	38.98
Operating expenses and outside coal purchases	$	406,045	$	391,436	$	32.04	$	28.75

Coal sales. Coal sales for the 2009 Period increased 13.0% to $599.9 million from $530.7 million for the 2008 Period. The increase of $69.2 million in coal sales reflected the benefit of higher average coal sales prices (contributing $105.8 million of the increase) partially offset by lower sales volume (reducing coal sales by $36.6 million). Average coal sales prices increased $8.35 per ton sold to $47.33 per ton in the 2009 Period as compared to the 2008 Period, primarily as a result of improved contract pricing across all operations.

Operating expenses. Operating expenses increased 4.4% to $400.9 million for the 2009 Period from $384.0 million for the 2008 Period. Higher operating expenses of $16.9 million resulted from increases and decreases associated with the specific factors listed below:

• Labor and benefit expenses per ton produced, excluding workers’ compensation, increased to $10.92 per ton in the 2009 Period from $8.94 per ton in the 2008 Period. The increase of $1.98 per ton represents pay rate increases and higher benefit expenses, particularly increased

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health care costs and retirement expenses, and the impact of increased headcount as we continue to hire and train new employees for the River View and Tunnel Ridge mine development projects;

• Workers’ compensation expenses per ton produced increased to $1.15 per ton in the 2009 Period from $0.79 per ton in the 2008 Period. The increase of $0.36 per ton produced primarily reflected a non-cash charge during the 2009 Period that resulted from discount rate changes, which increased the accrued liabilities for the present value of estimated future claim payments;

• Material and supplies per ton produced decreased slightly to $9.41 per ton in the 2009 Period from $9.45 per ton in the 2008 Period. This decrease per ton produced resulted from decreased costs for certain products and services particularly roof bolts, outside services, mine transportation, seals and fuel used in the mining process offset in part by higher power costs and additional supplies associated with the 2009 first quarter weather disruptions in the Illinois Basin region and reduced product recovery, among other factors;

• Maintenance expenses per ton produced increased 20.1% to $3.71 per ton in the 2009 Period from $3.09 per ton in the 2008 Period. The increase of $0.62 per ton produced resulted from higher repair costs related to continuous miners, belt conveyor equipment and other equipment categories;

• Operating expenses decreased due to a 924,000 ton reduction in produced tons sold due to first quarter weather disruptions in western Kentucky, particularly at the Dotiki, Warrior and Elk Creek mines, as well as unplanned customer outages and lower export and spot demand;

• Production taxes and royalties expenses (which were incurred as a percentage of coal sales and coal volumes) increased $3.5 million in the 2009 Period compared to the 2008 Period primarily as a result of increased average coal sales prices, partially offset by reduced tons sold;

• Expenses incurred during the 2009 Period relating to our River View and Tunnel Ridge organic growth projects increased $3.8 million over the 2008 Period; and

• The 2008 Period benefited from a $1.9 million gain on settlement of claims relating to the Vertical Belt Incident at our Pattiki mine.

General and administrative. General and administrative expenses for the 2009 Period decreased to $19.0 million compared to $21.0 million in the 2008 Period. The decrease was primarily due to lower incentive compensation expense, partially offset by higher salary and benefit costs primarily related to increased staffing levels.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, products and services provided by MAC and Matrix Design, and other outside services and administrative services revenue from affiliates. Other sales and operating revenues increased to $9.6 million for the 2009 Period from $7.5 million for the 2008 Period. The increase of $2.1 million was primarily attributable to increased revenues from transloading revenues and Matrix Design product sales partially offset by decreases in other outside services and MAC product sales.

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Outside coal purchases. Outside coal purchases decreased to $5.2 million for the 2009 Period from $7.5 million in the 2008 Period. The decrease of $2.3 million was primarily attributable to a decrease in outside coal purchases at our Northern Appalachian region in response to a weak demand in export and spot coal markets partially offset by increased outside coal purchases in the Central Appalachian region to supply attractive opportunities in the spot markets that were available in the first quarter of 2009.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $55.6 million for the 2009 Period from $48.9 million for the 2008 Period. The increase of $6.7 million was primarily attributable to additional depreciation expense associated with continuing capital expenditures related to infrastructure improvements, efficiency projects and expansion of production capacity.

Interest expense. Interest expense, net of capitalized interest increased to $15.8 million for the 2009 Period from $6.2 million for the 2008 Period. The increase of $9.6 million was principally attributable to the increased interest expense resulting from the 2008 financing activities, partially offset by reduced interest expense from our August 2008 principal payment of $18.0 million on our original senior notes issued in 1999. The 2008 financing activities are discussed in more detail below under “–Debt Obligations.”

Interest income. Interest income increased to $0.9 million for the 2009 Period from $0.3 million for the 2008 Period. The increase of $0.6 million resulted from increased interest income earned on short-term investments purchased with proceeds from the 2008 financing activities, which are discussed in more detail below under “–Debt Obligations.”

Transportation revenues and expenses. Transportation revenues and expenses each increased to $23.7 million for the 2009 Period compared to $21.6 million for the 2008 Period. The increase of $2.1 million was primarily attributable to increased coal sales volumes in the 2009 Period for which we arranged the transportation compared to the 2008 Period, partially offset by a decrease in average transportation rates of $0.21 on a per ton basis in the 2009 Period compared to the 2008 Period reflecting in part lower fuel costs. The cost of transportation services are passed through to our customers. Consequently, we do not realize any gain or loss on transportation revenues.

Income before income taxes. Income before income taxes for the 2009 and 2008 Periods was $114.4 million and $79.4 million, respectively, and the increase reflects the impact of the changes in revenues and expenses described above.

Income tax expense (benefit). Income tax expense for the 2009 Period was $0.2 million compared to income tax benefit of $0.7 million for the 2008 Period. The income tax expense for the 2009 Period was primarily due to operating income of Matrix Design, which is owned by our subsidiary, ASI. The income tax benefit for the 2008 Period was primarily due to operating losses of Matrix Design.

Net income attributable to noncontrolling interest. The noncontrolling interest represents a 50% third-party interest in MAC. The third-party’s portion of MAC’s net income was $179,000 for the 2009 Period and $243,000 for the 2008 Period. For more information about MAC, please read “Item 1. Financial Statements (Unaudited) – Note 11. Noncontrolling Interest” of this Quarterly Report on Form 10-Q.

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Segment Adjusted EBITDA. Our 2009 Period Segment Adjusted EBITDA increased $48.7 million to a record $203.9 million from the 2008 Period Segment Adjusted EBITDA of $155.2 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are (in thousands):

	Six Months Ended June 30,						Increase/(Decrease)
	2009			2008
Segment Adjusted EBITDA
Illinois Basin	$	167,770		$	104,756		$	63,014		60.2	%
Central Appalachia		22,969			28,049			(5,080	)	(18.1	)%
Northern Appalachia		8,337			16,611			(8,274	)	(49.8	)%
Other and Corporate		4,909			5,731			(822	)	(14.3	)%
Elimination		(82	)		18			(100	)	(1	)
Total Segment Adjusted EBITDA (2)	$	203,903		$	155,165		$	48,738		31.4	%
Tons sold
Illinois Basin		10,025			10,324			(299	)	(2.9	)%
Central Appalachia		1,379			1,712			(333	)	(19.5	)%
Northern Appalachia		1,270			1,580			(310	)	(19.6	)%
Other and Corporate		—			—			—		—
Elimination		—			—			—		—
Total tons sold		12,674			13,616			(942	)	(6.9	)%
Coal sales
Illinois Basin	$	439,491		$	352,559		$	86,932		24.7	%
Central Appalachia		94,786			101,846			(7,060	)	(6.9	)%
Northern Appalachia		65,146			76,320			(11,174	)	(14.6	)%
Other and Corporate		457			—			457		(1	)
Elimination		—			—			—		—
Total coal sales	$	599,880		$	530,725		$	69,155		13.0	%
Other sales and operating revenues
Illinois Basin	$	804		$	718		$	86		12.0	%
Central Appalachia		128			161			(33	)	(20.5	)%
Northern Appalachia		1,475			2,140			(665	)	(31.1	)%
Other and Corporate		17,478			9,120			8,358		91.6	%
Elimination		(10,245	)		(4,679	)		(5,566	)	(1	)
Total other sales and operating revenues	$	9,640		$	7,460		$	2,180		29.2	%
Segment Adjusted EBITDA Expense
Illinois Basin	$	272,524		$	248,521		$	24,003		9.7	%
Central Appalachia		71,945			76,748			(4,803	)	(6.3	)%
Northern Appalachia		58,284			61,849			(3,565	)	(5.8	)%
Other and Corporate		13,027			8,547			4,480		52.4	%
Elimination		(10,163	)		(4,696	)		(5,467	)	(1	)
Total Segment Adjusted EBITDA Expense (3)	$	405,617		$	390,969		$	14,648		3.7	%

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

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(2) Segment Adjusted EBITDA is defined as net income before net interest expense, income taxes, depreciation, depletion and amortization, net income attributable to noncontrolling interest and general and administrative expenses. Consolidated EBITDA 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 its 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 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 and Net Income of ARLP (in thousands):

	Six Months Ended June 30,
	2009			2008
Segment Adjusted EBITDA	$	203,903		$	155,165
General and administrative		(19,041	)		(20,950	)
Depreciation, depletion and amortization		(55,622	)		(48,894	)
Interest expense, net		(14,865	)		(5,943	)
Income tax (expense) benefit		(225	)		725
Net income		114,150			80,103
Net income attributable to noncontrolling interest		(179	)		(243	)
Net income of ARLP	$	113,971		$	79,860

(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. Segment Adjusted EBITDA Expense is used as a supplemental financial measure by our management to assess the operating performance of our segments. Segment Adjusted EBITDA Expense is a key component of EBITDA in addition to coal sales and other sales and operating revenues. The exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA Expense allows management to focus solely on the evaluation of segment operating performance as it primarily relates to our operating expenses. Outside coal purchases are included in Segment Adjusted EBITDA Expense because tons sold and coal sales include sales from outside coal purchases.

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The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to Operating expense (in thousands):

	Six Months Ended June 30,
	2009			2008
Segment Adjusted EBITDA Expense	$	405,617		$	390,969
Outside coal purchases		(5,192	)		(7,455	)
Other income		428			467
Operating expense (excluding depreciation, depletion and amortization)	$	400,853		$	383,981

Illinois Basin – Segment Adjusted EBITDA, as defined in reference (2) to the table above, increased 60.2% to $167.8 million for the 2009 Period from $104.8 million for the 2008 Period. The increase of $63.0 million was primarily attributable to improved contract pricing resulting in a higher average coal sales price of $43.84 per ton during the 2009 Period compared to $34.15 per ton for the 2008 Period. The benefit of higher average coal sales price was partially offset by reduced tons sold due to weather disruptions in western Kentucky, particularly at the Dotiki, Warrior and Elk Creek mines, as well as unplanned customer outages during the 2009 Period and the $1.9 million gain on settlement of claims relating to the Pattiki Vertical Belt Incident during the 2008 Period, as discussed above under consolidated operating expenses. Total Segment Adjusted EBITDA Expense, as defined in reference (3) to the above table, for the 2009 Period increased 9.7% to $272.5 million from $248.5 million in the 2008 Period. The increase in the 2009 Period Segment Adjusted EBITDA Expense compared to the 2008 Period was primarily the result of cost increases described above under consolidated operating expenses and the impact of weather disruptions which were partially offset by lower costs due to reduced tons sold during the 2009 Period. On a per ton basis, Segment Adjusted EBITDA Expense for the 2009 Quarter increased $3.11 to $27.18 per ton as compared to the 2008 Period Segment Adjusted EBITDA Expense of $24.07 per ton.

Central Appalachia – Segment Adjusted EBITDA, as defined in reference (2) to the table above, decreased $5.1 million, or 18.1%, to $23.0 million for the 2009 Period, compared to $28.1 million for the 2008 Period. The decrease was primarily the result of lower sales volumes due to weak coal demand in the spot market during the 2009 Period, partially offset by improved contract pricing that resulted in an increase in the average coal sales price of $9.25 per ton to $68.75 per ton in the 2009 Period, as compared to $59.50 per ton in the 2008 Period. Although Segment Adjusted EBITDA Expense for the 2009 Period decreased 6.3% to $71.9 million from $76.7 million in the 2009 Period primarily as a result of lower coal sales, Segment Adjusted EBITDA Expense per ton sold during the 2009 Period increased $7.34 per ton to $52.18, or 16.4% over the 2008 Period Segment Adjusted EBITDA Expense per ton of $44.84 (for a definition of Segment Adjusted EBITDA Expense, see reference (3) to the above table). The increase in the Segment Adjusted EBITDA Expense per ton resulted in part from decreased coal production in response to lower spot market demand and lower productivity due to Pontiki’s transition from the depleted Pond Creek coal seam into the thinner Van Lear coal seam during the 2009 Period. In addition, on a per ton basis, higher Segment Adjusted EBITDA Expenses resulted from increased materials and supplies primarily related to lower product recoveries and costs increases described above under consolidated operating expense. Segment Adjusted EBITDA in the 2008 Period benefited from the $2.8 million gain recognized on settlement of claims from the third-party that provided security services at the time of the MC Mining Fire Incident as discussed above under results of operations.

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Northern Appalachia – Segment Adjusted EBITDA, as defined in reference (2) to the table above, decreased 49.8%, to $8.3 million for the 2009 Period, compared to $16.6 million for the 2008 Period. The decrease of $8.3 million was primarily the result of lower sales volumes during the 2009 Period reflecting reduced spot market sales resulting in lower tons sold, and higher Segment Adjusted EBITDA Expense per ton sold during the 2009 Period of $45.88 per ton, an increase of $6.74 per ton, or 17.2%, as compared to $39.14 per ton in the 2008 Period (for a definition of Segment Adjusted EBITDA Expense, see reference (3) to the above table). Increased Segment Adjusted EBITDA Expense per ton in the 2009 Period, resulted primarily from lower production, which was impacted by a longwall move, an additional reduction in longwall run-days and a curtailment of third-party mining operations during the 2009 Period, as well as the other cost increases described above under consolidated operating expenses, including higher expenses incurred related to our Tunnel Ridge organic growth project. Lower production was primarily in response to weak demand in export and spot coal markets. Although Segment Adjusted EBITDA Expense per ton sold increased in the 2009 Period, Segment EBITDA Expense for the 2009 Period decreased 5.8% to $58.3 million from $61.8 million in the 2008 Period, primarily as a result of lower coal sales offset in part by higher expenses per ton as described above. Coal sales benefited from a higher average coal sales price of $51.28 per ton for the 2009 Period as compared to $48.30 per ton for the 2008 Period reflecting improved contract sales prices partially offset by lower spot market prices.

Other and Corporate – Segment Adjusted EBITDA, as defined in reference (2) to the above table, decreased to $4.9 million in the 2009 Period from $5.7 million in the 2008 Period, primarily due to a $5.2 million gain on sale of non-core coal reserves in the 2008 Period, partially offset by increased Matrix Design product sales and service revenues and Mt. Vernon transloading revenue in the 2009 Period. The increase in Segment Adjusted EBITDA Expense, as defined in reference (3) to the above table, primarily reflects increased cost associated with higher outside services revenue and product sales.

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 the current cash on hand along with cash generated from operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major capital improvements or acquisitions), scheduled debt payments and distribution payments. Our ability to satisfy our obligations and planned expenditures will depend upon our future operating performance and access to financing sources, which will be affected by prevailing economic conditions generally and in the coal industry specifically, some of 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 is materially lower than expected, including the impact of increases in interest rates, future liquidity may be adversely affected. Please see “Item 1A. Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2008.

Cash Flows

Cash provided by operating activities was $164.3 million for the 2009 Period compared to $150.8 million for the 2008 Period. The increase in cash provided by operating activities was principally attributable to higher net income, partially offset by reduced cash flow related to increases in certain operating assets such as trade receivables and inventory.

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Net cash used in investing activities was $169.6 million for the 2009 Period compared to $72.1 million for the 2008 Period. The increase in cash used for investing activities was primarily attributable to an increase in capital expenditures related to the continuing mine development at the River View and Tunnel Ridge growth projects, as well as the purchase of $4.5 million in marketable securities. There were no significant acquisitions or sales of coal reserves and other assets in the 2009 Period as compared to a net use of $6.1 million on such transactions in the 2008 Period. Additionally, timing of materials and services receipts, vendor invoices and related payments of accounts payable and accrued liabilities for capital expenditures during the 2009 Period reduced cash used for capital expenditures in the 2009 Period.

Net cash used in financing activities was $82.3 million for the 2009 Period compared to net cash provided by financing activities of $281.6 million for the 2008 Period. The decrease in cash provided by financing activities was primarily attributable to an absence of additional proceeds from borrowings in the 2009 Period compared to proceeds in the 2008 Period that included the issuance of the $350 million of senior notes in a private placement (see “—Debt Obligations” below) in addition to increased distributions paid to partners in the 2009 Period.

Capital Expenditures

Capital expenditures increased to $174.7 million in the 2009 Period from $71.0 million in the 2008 Period. See “—Cash Flows” above concerning this increase in capital expenditures. Our anticipated total capital expenditures for the year ending December 31, 2009 are estimated in a range of $350 to $400 million. Management anticipates funding remaining 2009 capital requirements with cash and cash equivalents ($157.4 million as of June 30, 2009), cash flows provided by operations and borrowing available under our revolving credit facility as discussed below. The terms of our credit facility require us to seek a waiver or amendment from our lenders if our Intermediate Partnership incurs capital expenditures, excluding acquisitions, in excess of $328.9 million in 2009. Should a waiver or amendment be required, we do not expect the cost of obtaining the same to have a material impact on our financial condition or results of operations. We will continue to have significant capital requirements over the long-term, which may require us to incur debt or seek additional equity capital. The availability 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. On September 25, 2007 our Intermediate Partnership entered into a $150.0 million revolving credit facility (“ARLP Credit Facility”), which matures in 2012. Borrowings under the ARLP Credit Facility bear interest based on a floating base rate plus an applicable margin. The applicable margin is based on a leverage ratio of our Intermediate Partnership, as computed from time to time. For London Interbank Offered Rate (“LIBOR”) borrowings, the applicable margin under the ARLP Credit Facility ranges from 0.625% to 1.150% over LIBOR. Outstanding letters of credit reduce amounts available under the ARLP Credit Facility. At June 30, 2009, we had $13.9 million of letters of credit outstanding with $136.1 million available for borrowing under the ARLP Credit Facility. We had no borrowings outstanding under the ARLP Credit Facility as of June 30, 2009. We incur an annual commitment fee of 0.175% on the undrawn portion of the ARLP Credit Facility.

Lehman Commercial Paper, Inc. (“Lehman”), a subsidiary of Lehman Brothers Holding, Inc., holds a 5%, or $7.5 million, commitment in our $150 million ARLP Credit Facility. The ARLP Credit Facility is underwritten by a syndicate of twelve financial institutions including Lehman with no individual institution representing more than 11.3% of the $150 million revolving credit facility. Lehman filed for protection under Chapter 11 of the Federal Bankruptcy Code in early October 2008. Although we have not made any borrowing requests since the bankruptcy filing by Lehman, we do not know if

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Lehman could, or would, fund its share of the commitment if requested. In the event Lehman, or any other financial institution in our syndicate, does not fund our future borrowing requests, our borrowing availability under the ARLP Credit Facility could be reduced. The obligations of the lenders under our credit facility are individual obligations and the failure of one or more lenders does not relieve the remaining lenders of their funding obligations.

Senior Notes. Our Intermediate Partnership has $108.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in six 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, which bear interest at 6.72% and mature on June 26, 2018 with interest payable semi-annually.

The proceeds from the Series A and Series B Senior Notes (collectively, the “2008 Senior Notes”) were used to repay $21.5 million outstanding under the ARLP Credit Facility and pay expenses associated with the offering. The remaining proceeds were placed in short-term investments pending their use to fund the development of the River View and Tunnel Ridge mining complexes and for other general working capital requirements. We incurred debt issuance costs of approximately $1.7 million associated with the 2008 Senior Notes, which have been deferred and are being amortized as a component of interest expense over the term of the respective notes.

The ARLP Credit Facility, Senior Notes and 2008 Senior Notes (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 (i) a minimum debt to cash flow ratio of not more than 3.0 to 1.0, (ii) a ratio of cash flow to interest expense during the four most recently ended fiscal quarters of not less than 4.0 to 1.0 and (iii) maximum annual capital expenditures, excluding acquisitions, of $328.9 million for the year ending December 31, 2009. The debt to cash flow ratio, cash flow to interest expense ratio and actual capital expenditures were 1.4 to 1.0, 9.8 to 1.0 and $174.7 million, respectively, for the trailing twelve months ended June 30, 2009. Regarding the 2009 maximum annual capital expenditures requirement, see “—Capital Expenditures” above. We were in compliance with the covenants of the ARLP Debt Arrangements as of June 30, 2009.

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 June 30, 2009, we had $31.1 million in letters of credit outstanding under agreements with these two banks. Our special general partner guarantees $5.0 million of these outstanding letters of credit.

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Related-Party Transactions

We have continuing related-party transactions with our managing general partner, AHGP and our special general partner 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 our special general partner and its affiliates, and guarantees from our special general partner for letters of credit.

Please read our Annual Report on Form 10-K for the year ended December 31, 2008, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Related-Party Transactions” for additional information concerning the related-party transactions described above.

New Accounting Standards

New Accounting Standards Issued and Adopted

In December 2007, the Financial Standards Accounting Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 141R, Business Combinations. SFAS No. 141R applies to all business combinations and establishes guidance for recognizing and measuring identifiable assets acquired, liabilities assumed, noncontrolling interests in the acquiree and goodwill. Most of these items are recognized at their full fair value on the acquisition date, including acquisitions where the acquirer obtains control but less than 100% ownership in the acquiree. SFAS No. 141R also requires expensing restructuring and acquisition-related costs as incurred and establishes disclosure requirements to enable the evaluation of the nature and financial effects of the business combination. SFAS No. 141R is effective for business combinations with an acquisition date in fiscal years beginning after December 15, 2008. We did not complete any business acquisitions during the 2009 Period.

On January 1, 2009, we adopted SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, which establishes accounting and reporting standards for noncontrolling ownership interests in subsidiaries. Noncontrolling ownership interests in consolidated subsidiaries is presented in the consolidated balance sheet within total partners’ capital as a separate component from the parent’s equity. Consolidated net income now includes earnings attributable to both the parent and the noncontrolling interests. Earnings per unit is based on earnings attributable to only the parent company and did not change upon adoption of SFAS No. 160. SFAS No. 160 provides guidance on accounting for changes in the parent’s ownership interest in a subsidiary, including transactions where control is retained and where control is relinquished. SFAS No. 160 also requires additional disclosure of information related to amounts attributable to the parent for income from continuing operations, discontinued operations and extraordinary items and reconciliations of the parent and noncontrolling interests’ equity of a subsidiary. SFAS No. 160 is applied prospectively to transactions involving noncontrolling interests, including noncontrolling interests that arose prior to the effective date, as of the beginning of 2009, the year of adoption. However, the presentation of noncontrolling interests within partners’ capital and the inclusion of earnings attributable to the noncontrolling interests in consolidated net income requires retrospective application to all periods presented. For more information, please read “Item 1. Financial Statements (Unaudited) – Note 11. Noncontrolling Interest” of this Quarterly Report on Form 10-Q.

On January 1, 2009, we adopted the FASB issued Emerging Issues Task Force (“EITF”) No. 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings Per Share, to Master Limited Partnerships, which considers whether the IDR of a master limited partnership represents a participating security when considered in the calculation of earnings per unit under the two-class method. The EITF also considers whether the partnership agreement contains any contractual limitations concerning distributions to IDR holders that would impact the amount of earnings to allocate to the IDR holders for each reporting period. If distributions are contractually limited to the IDR holders’ share of

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currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the IDR holders. We believe our partnership agreement contractually limits our distributions to available cash and therefore, undistributed earnings are no longer allocated to the IDR holder as provided under EITF No. 07-4. Accordingly, the adoption of EITF No. 07-4 impacts our presentation of earnings per unit in periods when Net Income of ARLP exceeds the aggregate distributions because undistributed earnings are no longer allocated to the IDR holder as previously prescribed under the provisions of EITF No. 03-6, Participating Securities and the Two-Class Method under FASB Statement No. 128, Earnings per Share. For more information, please read “Item 1. Financial Statements (Unaudited) – Note 6. Net Income of ARLP per Limited Partner Unit” of this Quarterly Report on Form 10-Q.

On January 1, 2009, we adopted the provisions of the FASB issued Staff Position (“FSP”) No. EITF No. 03-6-1 Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities. This FSP affects entities that accrue cash dividends on share-based payment awards during the awards’ service period when the dividends are not required to be returned if the employees forfeit the award. The FSP requires that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders and are considered participating securities. Because the awards are considered participating securities, the issuing entity is required to apply the two-class method of computing basic and diluted earnings per share. Based on the requirements of FSP No. EITF No. 03-6-1, we now include outstanding unvested awards under our Long-Term Incentive Plan in our calculation of basic weighted average limited partner units outstanding. For more information, please read “Item 1. Financial Statements (Unaudited) – Note 6. Net Income of ARLP per Limited Partner Unit” of this Quarterly Report on Form 10-Q.

We adopted FSP SFAS No. 107-1 and Accounting Principles Board (“APB”) Opinion No. 28-1, Interim Disclosures about Fair Value of Financial Instruments, beginning with the 2009 Quarter. FSP SFAS No. 107-1 and APB No. 28-1 amend SFAS No. 107, Disclosures about Fair Values of Financial Instruments, to require disclosures about fair value of financial instruments in interim financial statements as well as in annual financial statements. FSP SFAS No. 107-1 and APB No. 28-1 also amend APB Opinion No. 28, Interim Financial Reporting, to require those disclosures in all interim financial statements. For more information, please read “Item 1. Financial Statements (unaudited) —Note 5. Fair Value Measurements” of this Quarterly Report on Form 10-Q.

We adopted SFAS No. 165, Subsequent Events, beginning with the 2009 Quarter. SFAS No. 165 establishes the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date, that is, whether that date represents the date the financial statements were issued or were available to be issued. For more information, please read “Item 1. Financial Statements (unaudited)—Note 12. Subsequent Events” of this Quarterly Report on Form 10-Q.

New Accounting Standards Issued and Not Yet Adopted

In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles a replacement of FASB Statement No. 162, which is effective for interim periods ending after September 15, 2009. SFAS No. 168, establishes the FASB Accounting Standards Codification as the only source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. We will adopt the provisions of SFAS No. 168 beginning with the quarter ending September 30, 2009 and do not believe adoption of SFAS No. 168 will have a material impact on our financial statement consolidated disclosures.

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In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R), which amends FASB Interpretation (“FIN”) No. 46(R), Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, and changes the consolidation guidance applicable to a variable interest entity (“VIE”). SFAS No. 167 also amends the guidance governing the determination of whether an enterprise is the primary beneficiary of a VIE, and is, therefore, required to consolidate an entity, by requiring a qualitative analysis rather than a quantitative analysis. The qualitative analysis will include, among other things, consideration of who has the power to direct the activities of the entity that most significantly impact the entity’s economic performance and who has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. This standard also requires continuous reassessments of whether an enterprise is the primary beneficiary of a VIE. Previously, FIN No. 46(R) required reconsideration of whether an enterprise was the primary beneficiary of a VIE only when specific events had occurred. Qualifying special purpose entities, which were previously exempt from the application of this standard, will be subject to the provisions of this standard when it becomes effective. SFAS No. 167 also requires enhanced disclosures about an enterprise’s involvement with a VIE. The provisions of SFAS No. 167 are effective as of the beginning of interim and annual reporting periods that begin after November 15, 2009. We are currently evaluating the requirements of SFAS No. 167.

In December 2008, the FASB issued FSP SFAS No. 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets. FSP SFAS No. 132(R)-1 amends SFAS No. 132(R), Employer’s Disclosures about Pensions and Other Postretirement Benefits, to require more detailed annual disclosures about employers’ plan assets, concentrations of risk within plan assets and valuation techniques used to measure the fair value of plan assets. The provisions of FSP SFAS No. 132(R)-1 are effective for fiscal years ending after December 15, 2009. We are currently evaluating the requirements of FSP SFAS No. 132(R)-1. However, we do not anticipate that the adoption of FSP SFAS No. 132(R)-1 will have a material impact on our consolidated financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET 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.

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. We do not have any interest rate or commodity price-hedging transactions outstanding.

Borrowings under the ARLP Credit Facility are at variable rates and, as a result, we have interest rate exposure. Historically, our earnings have not been materially affected by changes in interest rates. We had no borrowings outstanding under the ARLP Credit Facility as of June 30, 2009.

As of June 30, 2009, the estimated fair value of the Senior Notes and the 2008 Senior Notes was approximately $456.2 million. The fair values of long-term debt are estimated using discounted cash flow analyses, based upon our current incremental borrowing rates for similar types of borrowing arrangements as of June 30, 2009. There were no other significant 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, 2008.

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ITEM 4. CONTROLS AND PROCEDURES

We maintain controls and procedures designed to ensure that information required to be disclosed in the reports we file with the U.S. Securities and Exchange Commission (“SEC”) is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. An evaluation of 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) was performed as of June 30, 2009. This evaluation was performed by our management, with the participation of our Chief Executive Officer and Chief Financial Officer. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective to ensure that the ARLP Partnership is able to collect, process and disclose the information it is required to disclose in the reports it files with the SEC within the required time periods, and during the quarterly period ended June 30, 2009, 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.

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FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 that are intended to come within the safe harbor protection provided by those sections. 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:

• increased competition in coal markets and our ability to respond to the competition;

• sustained decreases in coal prices, which could adversely affect our operating results and cash flows;

• decreases in spot market prices for coal;

• risks associated with the expansion of our operations and properties;

• 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;

• the impact and duration of the current worldwide economic downturn;

• liquidity constraints, including those resulting from the cost or unavailability of financing due to current credit market conditions;

• customer bankruptcies or cancellations or breaches to existing contracts;

• customer delays or defaults in making payments;

• fluctuations in coal demand, prices and availability due to labor and transportation costs and disruptions, equipment availability, governmental regulations, including those related to carbon 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;

• greater than expected increases in raw material costs;

• greater than expected shortage of skilled labor;

• any unanticipated increases in labor costs, adverse changes in work rules, or unexpected cash payments 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;

• coal market’s share of electricity generation;

• prices of fuel that compete with or impact coal usage, such as oil or natural gas;

• replacement of coal reserves;

• a loss or reduction of benefits from certain tax credits;

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

• other factors, including those discussed in Part II. Item 1A. “Risk Factors” and Item 1. “Legal Proceedings.”

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 risk factors described in “Risk Factors” below. The risk factors 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; and

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

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PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The information in Note 3. Contingencies to the Unaudited Condensed Consolidated Financial Statements included in “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” in the Annual Report on Form 10-K for the year ended December 31, 2008.

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, 2008 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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

31.1*	Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated August 7, 2009, 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 August 7, 2009, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated August 7, 2009, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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32.2* Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated August 7, 2009, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith (or furnished, in the case of Exhibits 32.1 and 32.2).

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, in Tulsa, Oklahoma, on August 7, 2009.

ALLIANCE RESOURCE PARTNERS, L.P.
By:	Alliance Resource Management GP, LLC
	its managing general partner
	/s/ Joseph W. Craft, III
	Joseph W. Craft, III
	President, Chief Executive Officer and Director, duly authorized to sign on behalf of the registrant.
	/s/ Brian L. Cantrell
	Brian L. Cantrell
	Senior Vice President and Chief Financial Officer

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