Alliance Resource Partners (ARLP) 10-Q 2010 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2010

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.     Yes  x    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  x    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 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  ¨    No  x

As of November 8, 2010, 36,716,855 common units are outstanding.

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION

		Page
ITEM 1.	Financial Statements (Unaudited)
	ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
	Condensed Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009		1
	Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2010 and 2009		2
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009		3
	Notes to Condensed Consolidated Financial Statements		4
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk		35
ITEM 4.	Controls and Procedures		35
	Forward-Looking Statements		36
	PART II
	OTHER INFORMATION
ITEM 1.	Legal Proceedings		38
ITEM 1A.	Risk Factors		38
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		40
ITEM 3.	Defaults upon Senior Securities		40
ITEM 4.	Reserved		40
ITEM 5.	Other Information		40
ITEM 6.	Exhibits		44

i

PART I

FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)

	September 30, 2010			December 31, 2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	20,294		$	21,556
Trade receivables		128,038			91,223
Other receivables		2,628			3,159
Due from affiliates		1,731			83
Inventories		41,125			64,357
Advance royalties		1,952			3,629
Prepaid expenses and other assets		669			8,801
Total current assets		196,437			192,808
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost		1,566,865			1,378,914
Less accumulated depreciation, depletion and amortization		(642,585	)		(556,370	)
Total property, plant and equipment, net		924,280			822,544
OTHER ASSETS:
Advance royalties		29,532			26,802
Other long-term assets		25,857			9,246
Total other assets		55,389			36,048
TOTAL ASSETS	$	1,176,106		$	1,051,400
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	69,710		$	62,821
Due to affiliates		433			27
Accrued taxes other than income taxes		15,368			10,777
Accrued payroll and related expenses		28,974			22,101
Accrued interest		6,543			2,918
Workers’ compensation and pneumoconiosis benefits		10,046			9,886
Current capital lease obligation		302			324
Other current liabilities		16,477			11,062
Current maturities, long-term debt		18,000			18,000
Total current liabilities		165,853			137,916
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities		404,000			422,000
Pneumoconiosis benefits		35,547			34,344
Accrued pension benefit		19,127			19,696
Workers’ compensation		65,989			53,845
Asset retirement obligations		54,254			53,116
Due to affiliates		1,693			1,148
Long-term capital lease obligation		240			460
Other liabilities		9,400			7,895
Total long-term liabilities		590,250			592,504
Total liabilities		756,103			730,420
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
Alliance Resource Partners, L.P. (“ARLP”) Partners’ Capital:
Limited Partners - Common Unitholders 36,716,855 and 36,661,029 units outstanding, respectively		723,944			630,165
General Partners’ deficit		(289,209	)		(293,153	)
Accumulated other comprehensive loss		(14,732	)		(17,149	)
Total ARLP Partners’ Capital		420,003			319,863
Noncontrolling interest		—			1,117
Total Partners’ Capital		420,003			320,980
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,176,106		$	1,051,400

See notes to condensed consolidated financial statements.

1

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except unit and per unit data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
SALES AND OPERATING REVENUES:
Coal sales	$	396,655		$	281,628		$	1,146,719		$	881,508
Transportation revenues		7,111			11,663			25,637			35,347
Other sales and operating revenues		6,682			6,353			19,096			15,993
Total revenues		410,448			299,644			1,191,452			932,848
EXPENSES:
Operating expenses (excluding depreciation, depletion and amortization)		264,388			204,840			750,357			605,693
Transportation expenses		7,111			11,663			25,637			35,347
Outside coal purchases		5,736			517			12,122			5,709
General and administrative		14,304			9,959			36,633			29,000
Depreciation, depletion and amortization		37,587			28,145			109,560			83,767
Total operating expenses		329,126			255,124			934,309			759,516
INCOME FROM OPERATIONS		81,322			44,520			257,143			173,332
Interest expense (net of interest capitalized for the three and nine months ended September 30, 2010 and 2009 of $67, $310, $758, and $857, respectively)		(7,633	)		(7,675	)		(22,667	)		(23,464	)
Interest income		47			112			146			1,036
Other income		460			126			614			554
INCOME BEFORE INCOME TAXES		74,196			37,083			235,236			151,458
INCOME TAX EXPENSE		995			586			1,586			811
NET INCOME		73,201			36,497			233,650			150,647
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		—			(53	)		—			(232	)
NET INCOME ATTRIBUTABLE TO ALLIANCE RESOURCE PARTNERS, L.P. (“NET INCOME OF ARLP”)	$	73,201		$	36,444		$	233,650		$	150,415
GENERAL PARTNERS’ INTEREST IN NET INCOME OF ARLP	$	18,416		$	15,192		$	53,415		$	44,813
LIMITED PARTNERS’ INTEREST IN NET INCOME OF ARLP	$	54,785		$	21,252		$	180,235		$	105,602
BASIC NET INCOME OF ARLP PER LIMITED PARTNER UNIT (Note 7)	$	1.48		$	0.57		$	4.86		$	2.85
DILUTED NET INCOME OF ARLP PER LIMITED PARTNER UNIT (Note 7)	$	1.48		$	0.57		$	4.86		$	2.85
DISTRIBUTIONS PAID PER LIMITED PARTNER UNIT	$	0.81		$	0.745		$	2.375		$	2.19
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING - BASIC		36,716,855			36,661,029			36,708,266			36,653,710
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING - DILUTED		36,716,855			36,661,029			36,708,266			36,653,710

See notes to condensed consolidated financial statements.

2

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2010			2009
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	394,243		$	238,349
CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(233,773	)		(251,453	)
Changes in accounts payable and accrued liabilities		(6,298	)		5,084
Proceeds from sale of property, plant and equipment		353			1
Purchase of marketable securities		—			(4,527	)
Receipts of prior advances on Gibson rail project		1,597			1,828
Net cash used in investing activities		(238,121	)		(249,067	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facilities		95,000			—
Payments under revolving credit facilities		(95,000	)		—
Payments on capital lease obligation		(242	)		(261	)
Payment on long-term debt		(18,000	)		(18,000	)
Net settlement of employee withholding taxes on vesting of Long-Term Incentive Plan		(1,265	)		(791	)
Cash contributions by General Partners		43			31
Distributions paid to Partners		(137,646	)		(123,689	)
Net cash used in financing activities		(157,110	)		(142,710	)
EFFECT OF CURRENCY TRANSLATION ON CASH		(274	)		187
NET CHANGE IN CASH AND CASH EQUIVALENTS		(1,262	)		(153,241	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		21,556			244,875
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	20,294		$	91,634
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	19,354		$	20,734
Cash paid for income taxes	$	888		$	225
NON-CASH INVESTING AND FINANCING ACTIVITY:
Accounts payable for purchase of property, plant and equipment	$	14,521		$	20,176
Market value of common units vested in Long-Term Incentive Plan before minimum statutory tax withholding requirements	$	3,396		$	2,333

See notes to condensed consolidated financial statements.

3

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.

4

Basis of Presentation

The accompanying condensed consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of September 30, 2010 and December 31, 2009, results of our operations for the three and nine months ended September 30, 2010 and 2009 and our cash flows for the nine months ended September 30, 2010 and 2009. All of our intercompany transactions and accounts have been eliminated. Net income attributable to Alliance Resource Partners, L.P. within our accompanying 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, 2009.

Use of Estimates

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

2. NEW ACCOUNTING STANDARDS

New Accounting Standards Issued and Adopted

In December 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2009-17,Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities (“ASU 2009-17”). ASU 2009-17 codified Statement of Financial Accounting Standards No. 167,Amendments to FASB Interpretation No. 46(R)),which changed the consolidation guidance applicable to a variable interest entity (“VIE”). ASU 2009-17 updated the guidance governing the determination of whether an enterprise is the primary beneficiary of a VIE, and is, therefore, required to consolidate such VIE, by requiring a qualitative analysis rather than a quantitative analysis. The qualitative analysis includes, among other things, consideration of whether the enterprise has the power to direct the activities of the entity that most significantly impact the entity’s economic performance and has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. ASU 2009-17 also requires continuous reassessments of whether an enterprise is the primary beneficiary of a VIE. Previously, FASB Accounting Standards Codification (“ASC”) 810,Consolidation, 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, are now subject to the provisions of ASU 2009-17. In addition, ASU 2009-17 also requires enhanced disclosures about an enterprise’s involvement with a VIE. The provisions of ASU 2009-17 were effective as of the beginning of interim and annual reporting periods that began after November 15, 2009. Based on our evaluation of ASU 2009-17, we deconsolidated Mid-America Carbonates, LLC (“MAC”) upon adoption, effective January 1, 2010 (Note 13). The deconsolidation of MAC did not have a material impact on our condensed consolidated financial statements.

5

In January 2010, the FASB issued ASU 2010-06,Improving Disclosures About Fair Value Measurements(“ASU 2010-06”). ASU 2010-06 amended guidance on certain aspects of FASB ASC 820,Fair Value Measurements and Disclosures,to add new requirements for disclosures of transfers into and out of Level 1 and 2 measurements and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements, all on a gross basis. ASU 2010-06 also clarifies existing fair value disclosures regarding the level of disaggregation and the inputs and valuation techniques used to measure fair value. The provisions of ASU 2010-06 were effective for the first reporting period beginning after December 15, 2009, except for the requirement to provide Level 3 activity of purchases, sales, issuances, and settlements on a gross basis, which will be effective for fiscal years beginning after December 15, 2010. The adoption of ASU 2010-06 did not have an impact on our condensed consolidated financial statements.

3. CONTINGENCIES

Various lawsuits, claims and regulatory proceedings incidental to our business are pending against the ARLP Partnership. We record an accrual for a potential loss related to these matters when, in management’s opinion, such loss is probable and reasonably estimable. Based on known facts and circumstances, we believe the ultimate outcome of these outstanding lawsuits, claims and regulatory proceedings will not have a material adverse effect on our financial condition, results of operations or liquidity. However, if the results of these matters were different from management’s current opinion and in amounts greater than our accruals, then they could have a material adverse effect.

The matters referenced in the previous paragraph include, but are not limited to, theGeorge W. Rector v. White County Coal, LLClawsuit, which is a royalty dispute involving certain coal leases that had been previously terminated. Plaintiffs have alleged damages of $33 million or more and have also asserted a claim for punitive damages. A bench trial of this case was concluded in November 2009 and closing arguments were heard on February 10, 2010, but we have not received written decision from the court. We believe plaintiffs’ claims are without merit, have accrued no loss and are vigorously defending the litigation.

4. PATTIKI VERTICAL HOIST CONVEYOR SYSTEM FAILURE

On May 13, 2010, White County Coal, LLC’s (“White County Coal”) Pattiki mine was temporarily idled following the failure of the vertical hoist conveyor system used in conveying raw coal out of the mine. On July 19, 2010, White County Coal’s efforts to repair the vertical hoist conveyor system had progressed sufficiently to allow resumption of limited production operations. Our operating expenses for the nine months ended September 30, 2010 includes $1.2 million for retirement of certain assets related to the failed vertical hoist conveyor system in addition to other repair and clean-up expenses that were not significant on a consolidated or segment basis. We are conducting a final review of our commercial property (including business interruption) insurance policies, which at the time of the equipment failure provided for self-retention, various deductibles and 22% co-insurance for the first $50 million in coverage. As the loss on the vertical hoist conveyor system did not exceed our deductible for property damage, we currently believe recovery is unlikely under such policies.

6

While the Pattiki mine was temporarily idled, we expanded coal production at our other coal mines in the region, including the addition of the seventh and eighth production units at the River View Coal, LLC’s (“River View”) mine, to partially offset the loss of production from the Pattiki mine. Consequently, the temporary idling of the Pattiki mine did not have a material adverse impact on our results of operations and cash flows. On July 19, 2010, the Pattiki mine resumed limited production while White County Coal continues to assess the effectiveness and reliability of the repaired vertical hoist conveyor system until such time it determines the system can be operated at full capacity. We are now operating six unit shifts at Pattiki and plan to add two more unit shifts during the quarter ending December 31, 2010, bringing Pattiki back to full capacity by the end of the year.

5. FAIR VALUE MEASUREMENTS

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

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

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

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

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

The carrying amounts for accounts receivable and accounts payable approximate fair value because of the short maturity of those instruments. At September 30, 2010 and December 31, 2009, the estimated fair value of our fixed rate term debt, including current maturities, was approximately $482.1 million and $460.7 million, respectively, based on interest rates that we believe are currently available to us for issuance of debt with similar terms and remaining maturities (Note 6).

6. LONG-TERM DEBT

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

	September 30, 2010			December 31, 2009
Revolving credit facility	$	—		$	—
Senior notes		72,000			90,000
Series A senior notes		205,000			205,000
Series B senior notes		145,000			145,000
		422,000			440,000
Less current maturities		(18,000	)		(18,000	)
Total long-term debt	$	404,000		$	422,000

The Intermediate Partnership has a $150.0 million revolving credit facility (“ARLP Credit Facility”), $72.0 million in senior notes and $205.0 million in Series A and $145.0 million in Series B senior notes (collectively, the “ARLP Debt Arrangements”), which are guaranteed by all of the direct and

7

indirect subsidiaries of our Intermediate Partnership. The ARLP Debt Arrangements contain various covenants affecting our Intermediate Partnership and its subsidiaries restricting, among other things, the amount of distributions by our Intermediate Partnership, the incurrence of additional indebtedness and liens, the sale of assets, the making of investments, the entry into mergers and consolidations and the entry into transactions with affiliates, in each case subject to various exceptions. The ARLP Debt Arrangements also require the Intermediate Partnership to remain in control of a certain amount of mineable coal reserves relative to its annual production. In addition, the ARLP Debt Arrangements require our Intermediate Partnership to maintain the following: (i) debt to cash flow ratio of not more than 3.0 to 1.0, (ii) cash flow to interest expense ratio of not less than 4.0 to 1.0, in each case, during the four most recently ended fiscal quarters and (iii) maximum annual capital expenditures, excluding acquisitions, of $471.8 million for 2010. The debt to cash flow ratio and cash flow to interest expense ratio were 0.77 to 1.0 and 17.5 to 1.0, respectively, for the trailing twelve months ended September 30, 2010. Actual capital expenditures were $233.8 million for the nine months ended September 30, 2010. We were in compliance with the covenants of the ARLP Debt Arrangements as of September 30, 2010.

Lehman Commercial Paper, Inc. (“Lehman”), a subsidiary of Lehman Brothers Holding, Inc., held a 5%, or $7.5 million, commitment in our $150 million ARLP Credit Facility. On February 11, 2010, we gave our lenders a notice of borrowing under the ARLP Credit Facility and, in response to that notice, Lehman notified us that it would not fund its proportionate share of the borrowing. As a result, as of February 11, 2010, Lehman became a defaulting lender and on October 6, 2010, was removed as a commitment holder under the ARLP Credit Facility. Consequently, availability for borrowing under the ARLP Credit Facility was reduced by $7.5 million.

At September 30, 2010, we had $11.6 million of letters of credit outstanding with $130.9 million available for borrowing under the ARLP Credit Facility. We had no borrowings outstanding under the ARLP Credit Facility as of September 30, 2010. We incur an annual commitment fee of 0.375% on the undrawn portion of the ARLP Credit Facility.

7. NET INCOME OF ARLP PER LIMITED PARTNER UNIT

We apply the provisions of FASB ASC 260,Earnings Per Share (“FASB ASC 260”). As required by FASB ASC 260, we apply the two-class method in calculating basic and diluted earnings per unit (“EPU”). 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 or expense allocations, including incentive distributions to our managing general partner, the holder of the IDR pursuant to our partnership agreement, which are declared and paid following the end of each quarter. Under the quarterly IDR provisions of our partnership agreement, our managing general partner is entitled to receive 15% of the amount we distribute in excess of $0.275 per unit, 25% of the amount we distribute in excess of $0.3125 per unit, and 50% of the amount we distribute in excess of $0.375 per unit. Our partnership agreement contractually limits our distributions to available cash and therefore, undistributed earnings of the ARLP Partnership are not allocated to the IDR holder. In addition, our outstanding unvested awards under our Long-Term Incentive Plan (“LTIP”) include rights to nonforfeitable distributions and are therefore considered participating securities. As such, we allocate undistributed and distributed earnings to the outstanding unvested awards in our calculation of EPU.

8

The following is a reconciliation of Net Income of ARLP and net income used for calculating basic earnings per unit and the weighted average units used in computing EPU for the three and nine months ended September 30, 2010 and 2009, respectively, (in thousands, except per unit data):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Net Income of ARLP	$	73,201		$	36,444		$	233,650		$	150,415
Adjustments:
General partner’s priority distributions		(17,297	)		(14,758	)		(49,736	)		(42,658	)
General partners’ 2% equity ownership		(1,119	)		(434	)		(3,679	)		(2,155	)
Limited partners’ interest in Net Income of ARLP		54,785			21,252			180,235			105,602
Less:
Distributions on LTIP awards outstanding		(314	)		(253	)		(923	)		(744	)
Undistributed earnings attributable to LTIP awards		(245	)		—			(919	)		(212	)
Net Income of ARLP available to limited partners	$	54,226		$	20,999		$	178,393		$	104,646
Weighted average limited partner units outstanding – Basic and Diluted		36,717			36,661			36,708			36,654
Basic and Diluted Net Income of ARLP per limited partner unit (1)	$	1.48		$	0.57		$	4.86		$	2.85

(1) Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. For the three and nine months ended September 30, 2010 and 2009, LTIP units of 253,294, 184,115, 219,187 and 157,829, respectively, were considered anti-dilutive under the treasury stock method.

8. WORKERS’ COMPENSATION AND PNEUMOCONIOSIS (“BLACK LUNG”)

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Beginning balance	$	70,050		$	63,082		$	63,220		$	56,671
Accruals increase		5,120			4,703			14,931			13,850
Payments		(2,494	)		(3,459	)		(7,312	)		(9,412	)
Interest accretion		833			864			2,499			2,592
Valuation loss		2,015			3,193			2,186			4,682
Ending balance	$	75,524		$	68,383		$	75,524		$	68,383

9

Pneumoconiosis

The Patient Protection and Affordable Care Act, which was signed into law by President Obama in March 2010, amended previous legislation related to coal workers’ Black Lung providing automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims. We are presently unable to estimate the impact of this legislation on our obligations and our future service period charges related to future claims due to uncertainty about the number of claims that will be filed, how the new award criteria will impact these claim populations and the effect of regulations relating to the retroactive application of certain criteria. We expect to complete an evaluation of the obligation by the end of fiscal year 2010 assuming regulations are issued by that time. For more information, please read “Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Health Care Reform” of this Quarterly Report on Form 10-Q.

9. COMPENSATION PLANS

We maintain the LTIP for certain employees and officers of our managing general partner and its affiliates who perform services for us. The LTIP awards are grants of non-vested notional units, which upon satisfaction of vesting requirements entitle the LTIP participant to receive ARLP common units. On January 26, 2010, the compensation committee of the board of directors (“Compensation Committee”) determined that the vesting requirements for the 2007 grants of 88,975 units (which are net of 4,500 forfeitures) had been satisfied as of January 1, 2010. As a result of this vesting, on February 12, 2010, we issued 55,826 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 February 1, 2010, the Compensation Committee authorized additional grants up to 143,145 restricted units, of which 138,130 were granted during the nine months ended September 30, 2010, all of which will vest on January 1, 2013 subject to satisfaction of certain financial tests. The fair value of these 2010 grants is equal to the intrinsic value at the date of grant, which was $39.59 per unit on a weighted average basis. LTIP expense was $1.0 million, $0.9 million, $2.9 million and $2.7 million for the three and nine months ended September 30, 2010 and 2009, respectively. On October 23, 2009, our unitholders approved the third amendment (“Third Amendment”) to the LTIP. The Third Amendment was previously authorized by the Board of Directors of our managing general partner, subject to unitholder approval. The Third Amendment increased the number of units available for issuance under the LTIP from 1.2 million to 3.6 million, providing 2.4 million units for satisfaction of future awards. After consideration of the January 1, 2010 vesting and subsequent issuance of 55,826 common units, approximately 2.3 million units remain available for issuance in the future, assuming all grants issued in 2008, 2009 and 2010 currently outstanding are settled with common units and no future forfeitures occur.

As of September 30, 2010, there was $5.9 million in total unrecognized compensation expense related to the non-vested LTIP grants that are expected to vest. That expense is expected to be recognized over a weighted-average period of 1.4 years. As of September 30, 2010, the intrinsic value of the non-vested LTIP grants was $22.1 million. As of September 30, 2010, the total obligation associated with the LTIP was $6.5 million and is included in the partners’ capital-limited partners line item in our condensed consolidated balance sheets.

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

10

10. COMPONENTS OF PENSION PLAN NET PERIODIC BENEFIT COSTS

Eligible employees at certain of our mining operations participate in a defined benefit plan (the “Pension Plan”) that we sponsor. The benefit formula for the Pension Plan is a fixed dollar unit based on years of service. Components of the net periodic benefit cost for each of the periods presented are as follows (in thousands):

	Three Months  Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Service cost	$	713		$	667		$	2,139		$	2,001
Interest cost		839			755			2,519			2,264
Expected return on plan assets		(922	)		(608	)		(2,768	)		(1,824	)
Amortization of net loss		269			355			806			1,066
Net periodic benefit cost	$	899		$	1,169		$	2,696		$	3,507

We previously disclosed in our financial statements for the year ended December 31, 2009 that we expected to contribute $9.8 million to the Pension Plan in 2010 for the 2009 plan year. During 2010, we received a final funding report for the 2009 plan year, which included updated assumptions on expected retirement patterns, interest rate analysis and asset value method. The finalization of these assumptions significantly decreased our required funding in 2010 for the 2009 plan year. During the nine months ended September 30, 2010, we made contribution payments of $1.1 million and $1.4 million for the 2009 and 2010 plan years, respectively. No further contribution payments are required for the 2009 plan year.

11. COMPREHENSIVE INCOME

Total comprehensive income for the three and nine months ended September 30, 2010 and 2009, respectively, is as follows (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010		2009			2010		2009
Net income	$	73,201	$	36,497		$	233,650	$	150,647
Other comprehensive income:
Unrealized (loss)/gain on marketable securities		—		(142	)		—		425
Actuarially determined long-term liability adjustments		1,879		355			2,417		1,066
Total other comprehensive income		1,879		213			2,417		1,491
Total comprehensive income		75,080		36,710			236,067		152,138
Less comprehensive income attributable to noncontrolling interest		—		(53	)		—		(232	)
Comprehensive income attributable to ARLP	$	75,080	$	36,657		$	236,067	$	151,906

Comprehensive income differs from net income due to unrealized (loss)/gain on our available for sale marketable securities resulting from valuation changes (2009 only) and net amortization of actuarial gains and losses associated with adoption of amendments to FASB ASC 715,Compensation – Retirement Benefits.

11

12. SEGMENT INFORMATION

We operate in the eastern U.S. as a producer and marketer of coal to major utilities and industrial users. 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.

The 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’s Pattiki mining complex, Warrior Coal, LLC’s mining complex, River View’s mining complex, which initiated operations in 2009, the Sebree Mining, LLC (“Sebree”) property, the Gibson County Coal (South), LLC (“Gibson South”) property and certain properties of Alliance Resource Properties, LLC (“Alliance Resource Properties”) and its wholly-owned subsidiary, ARP Sebree, LLC. We are in the process of permitting the Gibson South property and the Sebree 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 and restarted in February 2010), a mining complex currently under construction at Tunnel Ridge, LLC (“Tunnel Ridge”) and the Penn Ridge Coal, LLC (“Penn Ridge”) property. In May 2010, incidental production began from mine development activities at Tunnel Ridge; longwall production is not anticipated until late 2011. We are in the process of permitting the Penn Ridge property for future mine development.

Other and Corporate includes marketing and administrative expenses, Matrix Design Group, LLC (“Matrix Design”), Alliance Design Group, LLC (“Alliance Design”) (collectively, Matrix Design and Alliance Design are referred to as the “Matrix Group”), the Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) dock activities, coal brokerage activity, our equity investment in MAC and certain properties of Alliance Resource Properties. Segment results for the three and nine months ended September 30, 2010 and 2009 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 September 30, 2010:
Total revenues (2)	$	304,292	$	41,499	$	57,248	$	12,702	$	(5,293	)	$	410,448
Segment Adjusted EBITDA Expense (3)		185,183		33,175		46,268		10,331		(5,293	)		269,664
Segment Adjusted EBITDA (4)		114,215		8,307		8,781		2,370		—			133,673
Capital expenditures		35,611		3,389		19,512		413		—			58,925
Operating segment results for the three months ended September 30, 2009:
Total revenues (2)	$	217,128	$	41,401	$	36,041	$	9,489	$	(4,415	)	$	299,644
Segment Adjusted EBITDA Expense (3)		137,579		34,839		30,650		6,298		(4,135	)		205,231
Segment Adjusted EBITDA (4)		70,090		6,517		3,234		3,189		(280	)		82,750
Capital expenditures		54,274		3,845		17,589		1,060		—			76,768
Operating segment results for the nine months ended September 30, 2010:
Total revenues (2)	$	895,878	$	122,189	$	156,223	$	34,048	$	(16,886	)	$	1,191,452
Segment Adjusted EBITDA Expense (3)		532,626		97,921		119,855		28,349		(16,886	)		761,865
Segment Adjusted EBITDA (4)		344,216		24,141		29,892		5,701		—			403,950
Total assets		753,987		84,505		299,812		43,203		(5,401	)		1,176,106
Capital expenditures		119,000		7,909		105,503		1,361		—			233,773
Operating segment results for the nine months ended September 30, 2009:
Total revenues (2)	$	675,441	$	137,739	$	106,898	$	27,430	$	(14,660	)	$	932,848
Segment Adjusted EBITDA Expense (3)		410,103		106,784		88,934		19,325		(14,298	)		610,848
Segment Adjusted EBITDA (4)		237,860		29,486		11,571		8,098		(362	)		286,653
Total assets		684,823		90,141		178,259		117,334		(119	)		1,070,438
Capital expenditures		186,678		11,555		49,910		3,310		—			251,453

12

(1) The elimination column represents the elimination of intercompany transactions and is primarily comprised of sales from the Matrix Group and MAC (for 2009 only; see Note 13) to our mining operations.

(2) Revenues included in the Other and Corporate column are primarily attributable to the Matrix Group revenues, Mt. Vernon transloading revenues, administrative service revenues from affiliates, MAC rock dust revenues (for 2009 only; see Note 13) and brokerage sales.

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

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Segment Adjusted EBITDA Expense	$	269,664		$	205,231		$	761,865		$	610,848
Outside coal purchases		(5,736	)		(517	)		(12,122	)		(5,709	)
Other income		460			126			614			554
Operating expense (excluding depreciation, depletion and amortization)	$	264,388		$	204,840		$	750,357		$	605,693

(4) Segment Adjusted EBITDA (a non-GAAP financial measure ) is defined as Net Income of ARLP before net interest expense, income taxes, depreciation, depletion and amortization, net income attributable to noncontrolling interest and general and administrative expenses. Management therefore is able to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments. Consolidated Segment Adjusted EBITDA is reconciled to net income and Net Income of ARLP, the most comparable GAAP financial measure, as follows (in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Segment Adjusted EBITDA	$	133,673		$	82,750		$	403,950		$	286,653
General and administrative		(14,304	)		(9,959	)		(36,633	)		(29,000	)
Depreciation, depletion and amortization		(37,587	)		(28,145	)		(109,560	)		(83,767	)
Interest expense, net		(7,586	)		(7,563	)		(22,521	)		(22,428	)
Income tax expense		(995	)		(586	)		(1,586	)		(811	)
Net income		73,201			36,497			233,650			150,647
Net income attributable to noncontrolling interest		—			(53	)		—			(232	)
Net Income of ARLP	$	73,201		$	36,444		$	233,650		$	150,415

13

13. NONCONTROLLING INTEREST

We apply the provisions of FASB ASC 810,Consolidation, which were amended on January 1, 2010. Based on our evaluation of these amendments, we deconsolidated MAC effective January 1, 2010 (Note 2).

White County Coal and Alexander J. House (“House”) entered into a limited liability company agreement in 2006 to form MAC, which manufactures and sells rock dust. Consistent with prior years, we have a 50% ownership interest in MAC. Previously, we consolidated MAC’s financial results in accordance with FASB ASC 810. However, based on the provisions of ASU 2009-17, we concluded that we are no longer the primary beneficiary of MAC and thus deconsolidated MAC as House has the power to direct the activities that most significantly impact the entity’s economic performance.

We adopted the amendments to FASB ASC 810 on January 1, 2010. As a result, we reclassified $1.1 million from noncontrolling interest in partners’ capital to other long-term assets in our condensed consolidated balance sheets. We did not retrospectively apply the provisions of ASU 2009-17 as allowed by the amendments. Our equity investment in MAC is $1.3 million at September 30, 2010.

MAC has a $1.75 million Revolving Credit Agreement (“Revolver”) with ARLP. On November 17, 2009, MAC entered into Amendment No. 2, effective June 30, 2009, which increased the Revolver to $1.75 million from $1.5 million. The Revolver is scheduled to expire on December 31, 2010. At September 30, 2010, MAC owed ARLP $1.7 million under the Revolver, which is classified as Due from Affiliates on our condensed consolidated balance sheets.

14. SUBSEQUENT EVENTS

On October 27, 2010, we declared a quarterly distribution for the quarter ended September 30, 2010, of $0.83 per unit, on all common units outstanding, totaling approximately $48.4 million (which includes our managing general partner’s incentive distributions), payable on November 12, 2010 to all unitholders of record as of November 5, 2010.

Effective October 1, 2010, we completed our annual property and casualty insurance renewal for various insurance coverages. The aggregate maximum limit in the commercial property program is $75.0 million per occurrence excluding a $1.5 million deductible for property damage, a 60-day waiting period for business interruption and a $10.0 million overall aggregate deductible.

14

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

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

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

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

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

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

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

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

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

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

Summary

We are a diversified producer and marketer of coal primarily to major United States (“U.S.”) utilities and industrial users. We began mining operations in 1971 and, since then, have grown through acquisitions and internal development to become what we believe to be the fifth largest coal producer in the eastern U.S. We operate nine mining complexes in Illinois, Indiana, Kentucky, Maryland and West Virginia. We are constructing a new mining complex in West Virginia. We 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 (“Dotiki”), Gibson County Coal, LLC’s Gibson North mining complex (“Gibson”), Hopkins County Coal, LLC’s Elk Creek mining complex (“Hopkins”), White County Coal, LLC’s Pattiki mine (“Pattiki”), Warrior Coal, LLC’s (“Warrior”) mining complex, River View Coal, LLC’s (“River View”) mining complex, which initiated operations in 2009, the Sebree Mining, LLC (“Sebree”) property, the Gibson County Coal (South), LLC (“Gibson South”) property and certain properties of Alliance Resource Properties, LLC (“Alliance Resource Properties”) and its wholly-owned subsidiary, ARP Sebree, LLC. We are in the process of permitting the Gibson South property and the Sebree property for future mine development.

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

15

• Northern Appalachian segment is comprised of Mettiki Coal, LLC’s mining complex, (“Mettiki”), Mettiki Coal (WV), LLC’s Mountain View mining complex, two small third-party mining operations (one of which was idled in May 2009 and restarted in February 2010), a mining complex currently under construction at Tunnel Ridge, LLC (“Tunnel Ridge”) and the Penn Ridge Coal, LLC (“Penn Ridge”) property. In May 2010, incidental production began from mine development activities at Tunnel Ridge; longwall production is not anticipated until late 2011. We are in the process of permitting the Penn Ridge property for future mine development.

• Other and Corporate segment includes marketing and administrative expenses, Matrix Design Group, LLC (“Matrix Design”), Alliance Design Group, LLC (collectively, Matrix Design and Alliance Design Group, LLC are referred to as the “Matrix Group”), the Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) dock activities, coal brokerage activity, our equity investment in Mid-America Carbonates, LLC (“MAC”) and certain properties of Alliance Resource Properties.

Health Care Reform

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

The Health Care Act has both short-term and long-term implications on benefit plan eligibility, coverage requirements, and benefit standards and limitations. In the short term, our health care costs are expected to increase due to raising the maximum age and easing of eligibility limitations for covered dependents. The Health Care Act also prevents the group health plan from limiting benefit payments for participants who meet or exceed annual or lifetime dollar limits per covered individual. We do not currently expect raising the maximum age and easing of eligibility limitations for covered dependents to significantly increase our annual health care costs beginning in 2011. In addition, we currently expect removing the lifetime maximum to have an additional impact on us that we are unable to reasonably estimate at this time. While historically few participants have reached the plan lifetime maximum limit of $1 million, future federal and state mandates are expected to impact large claims costs and make this a potentially greater risk variable in the future. In the long term, our plan’s health care costs are expected to increase for various reasons due to the Health Care Act, including the potential impact of an excise tax on “high cost” plans (beginning in 2018), among other standard requirements. We have chosen not to “grandfather” our health care plan as allowed under the Health Care Act. Maintaining “grandfather” status prevents the plan from making plan benefit modifications that encourage participants to use high value, lower cost medical care options such as on-site medical services, generic preferred medications, and urgent care centers instead of emergency rooms.

We anticipate that certain government agencies will provide additional regulations or interpretations concerning the application of the Health Care Act and reporting required thereunder. Until these regulations or interpretations are published, we are unable to reasonably estimate the further impact of such federal mandate requirements on our future health care costs.

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

16

The Dodd – Frank Act

On July 21, 2010, President Obama signed into law the Dodd – Frank Wall Street Reform and Consumer Protection Act (“Dodd – Frank Act”). The Dodd Frank Act gives regulators new resolution authority, creates a new council to monitor and address systemic risk, changes the mandate of the Federal Reserve, imposes significant new regulations on banking organizations, makes significant changes to the rules that affect the process of financing business enterprises and creates a new governmental authority, the Bureau of Consumer Financial Protection, to regulate retail financial products and services, among many other provisions.

The additional regulations imposed by the Dodd – Frank Act on financial institutions may result in increased costs associated with future borrowings and decreased availability of credit. However, we are presently unable to determine the significance of any potential increase in our borrowing costs or potential liquidity constraints, if any. The Dodd – Frank Act also requires public mining companies to report certain safety information in each periodic report filed with the SEC and to file current reports on Form 8-K for certain safety matters. We are continuing to evaluate the effect of the Dodd – Frank Act on the Partnership’s operations.

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009

We reported record Net Income of ARLP of $73.2 million for the three months ended September 30, 2010 (“2010 Quarter”) compared to $36.4 million for the three months ended September 30, 2009 (“2009 Quarter”). This increase of $36.8 million was principally due to record tons sold and improved pricing resulting in a record quarterly average coal sales price of $51.68 per ton sold, as compared to $45.58 per ton sold for the 2009 Quarter. We had record tons sold of 7.7 million tons and higher tons produced of 7.1 million tons in the 2010 Quarter, compared to 6.2 million tons sold and 6.3 million tons produced in the 2009 Quarter. This increase in produced tons primarily reflects increased production from our new River View mine. Higher operating expenses during the 2010 Quarter resulted primarily from increased sales and production volumes, which particularly impacted materials and supplies expenses, sales-related expenses and labor and labor-related expenses. Increased operating expenses also reflect the new incidental production at our Tunnel Ridge mine development project and higher Northern Appalachia third-party contract mining costs.

	Three Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)				(per ton sold)
Tons sold		7,676		6,179		N/A		N/A
Tons produced		7,124		6,304		N/A		N/A
Coal sales	$	396,655	$	281,628	$	51.68	$	45.58
Operating expenses and outside coal purchases	$	270,124	$	205,357	$	35.19	$	33.23

Coal sales. Coal sales for the 2010 Quarter increased 40.8% to $396.7 million from $281.6 million for the 2009 Quarter. The increase of $115.1 million in coal sales reflected the benefit of record tons sold (contributing $68.2 million in coal sales) and record average coal sales prices (contributing $46.9 million in additional coal sales). Average coal sales prices in the 2010 Quarter increased $6.10 per ton sold to $51.68 per ton in the 2010 Quarter compared to $45.58 per ton in the 2009 Quarter primarily as a result of improved contract pricing across all regions.

Operating expenses. Operating expenses increased 29.1% to $264.4 million for the 2010 Quarter from $204.8 million for the 2009 Quarter primarily due to record coal sales and increased production volumes. Increased River View production and Tunnel Ridge development combined to increase certain operating expenses $32.5 million during the 2010 Quarter over the 2009 Quarter and are generally

17

included in the variances discussed further below. Operating expenses were impacted by various other factors, the most significant of which are also discussed below:

• Labor and benefit expenses per ton produced, excluding workers’ compensation, increased 0.3% to $11.07 per ton in the 2010 Quarter from $11.04 per ton in the 2009 Quarter. This increase of $0.03 per ton was primarily due to increased mine development labor at our Tunnel Ridge mine and increased regulatory oversight, particularly at our Central Appalachian mines, partially offset by lower labor cost per ton resulting from production at our new River View mine;

• Workers’ compensation expenses per ton produced decreased to $1.31 per ton in the 2010 Quarter from $1.64 per ton in the 2009 Quarter. The decrease of $0.33 per ton produced resulted primarily from a non-cash charge during the 2009 Quarter due to a discount rate change, which increased the accrued liabilities for the present value of estimated future claim payments, partially offset by unfavorable reserve adjustments for new claims incurred during the 2010 Quarter;

• Material and supplies expenses per ton produced increased 15.4% to $11.07 per ton in the 2010 Quarter from $9.59 per ton in the 2009 Quarter. The increase of $1.48 per ton produced resulted from an increase in cost for certain products and services, primarily outside services expenses (increase of $0.39 per ton), roof support (increase of $0.37 per ton), power and fuel used in the mining process (increase of $0.23 per ton), preparation plant cost (increase of $0.21 per ton), ventilation (increase of $0.17 per ton) and rock dust (increase of $0.11 per ton);

• Maintenance expenses per ton produced increased 5.6% to $3.75 per ton in the 2010 Quarter from $3.55 per ton in the 2009 Quarter. The increase of $0.20 per ton produced resulted primarily from higher maintenance costs for our mine development project at Tunnel Ridge and increased maintenance costs at our Warrior mine, primarily related to continuous miners, partially offset by the benefit of newer equipment and increased production at our new River View mine;

• Mine administration expenses increased $4.2 million for the 2010 Quarter compared to the 2009 Quarter, primarily due to higher costs resulting from increased Matrix Design product sales and higher mine administration expense at River View and our mine development project at Tunnel Ridge. In addition, increased estimated regulatory costs were incurred during the 2010 Quarter;

• Contract mining expenses increased $3.4 million for the 2010 Quarter compared to the 2009 Quarter. The increase primarily reflects the restart of a third-party mining operation in our Northern Appalachian region during February 2010 that was previously idled in May 2009 and increased production from our existing contract mining operations in Northern Appalachia, both in response to increased demand in the export coal market;

• Production taxes and royalties expenses (which were incurred as a percentage of coal sales prices and volumes) increased $0.62 per produced ton sold in the 2010 Quarter compared to the 2009 Quarter primarily as a result of increased average coal sales prices across all regions; and

• Operating expenses increased due to significant reduction in coal inventory for the 2010 Quarter reflecting higher coal sales, whereas the 2009 Quarter experienced an increase in coal inventory. The significant reduction in coal inventory was partially offset by the benefit of

18

lower cost per ton beginning coal inventory for the 2010 Quarter, particularly at the Illinois Basin and Central Appalachian regions.

General and administrative. General and administrative expenses for the 2010 Quarter increased to $14.3 million compared to $10.0 million in the 2009 Quarter. The increase of $4.3 million was primarily due to increases in retirement plan expense, incentive compensation expense and contributions to certain industry and advocacy groups.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, products and services provided by MAC (in the 2009 Quarter only), Matrix Design and other outside services and administrative services revenue from affiliates. Other sales and operating revenues increased to $6.7 million for the 2010 Quarter from $6.4 million for the 2009 Quarter. The increase of $0.3 million was primarily attributable to increased Matrix Design product sales, partially offset by decreased rock dust revenues reflecting the deconsolidation of MAC. For more information about MAC, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 13. Noncontrolling Interest” of this Quarterly Report on Form 10-Q.

Outside coal purchases. Outside coal purchases increased to $5.7 million for the 2010 Quarter compared to $0.5 million in the 2009 Quarter. The increase of $5.2 million was primarily attributable to increased outside coal purchases related to our Northern Appalachian region due to increased demand in the export coal markets as well as increased coal brokerage activity.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $37.6 million for the 2010 Quarter from $28.1 million for the 2009 Quarter. The increase of $9.5 million was attributable to additional depreciation expense associated with our River View mine and our Tunnel Ridge development project in addition to continuing capital expenditures related to various infrastructure improvements and efficiency projects.

Interest expense. Interest expense, net of capitalized interest, decreased to $7.6 million for the 2010 Quarter from $7.7 million for the 2009 Quarter. The decrease of $0.1 million was principally attributable to reduced interest expense resulting from our August 2010 principal repayment of $18.0 million on our original senior notes issued in 1999, partially offset by increased interest expense for borrowings on our $150.0 million revolving credit facility (“ARLP Credit Facility”) during the 2010 Quarter, each of which are discussed in more detail below under “–Debt Obligations.”

Transportation revenues and expenses. Transportation revenues and expenses were $7.1 million and $11.7 million for the 2010 and 2009 Quarters, respectively. The decrease of $4.6 million was primarily attributable to reduced tonnage for which we arrange transportation from our Warrior, Hopkins and Pattiki mines. The cost of transportation services are passed through to our customers. Consequently, we do not realize any gain or loss on transportation revenues.

Income tax expense. Income tax expense was $1.0 million for the 2010 Quarter compared to $0.6 million for the 2009 Quarter. Income taxes are primarily due to the operations of Matrix Design, which is owned by our subsidiary, Alliance Service, Inc. Increased taxes reflect higher net income in the 2010 Quarter from our Matrix Design operation.

Net income attributable to noncontrolling interest.The noncontrolling interest for the 2009 Quarter represents a 50% third-party interest in MAC. The third-party’s portion of MAC’s net income was $0.1 million for the 2009 Quarter. Effective January 1, 2010, we deconsolidated MAC based on amendments to the provisions of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 810,Consolidation. For more information about MAC, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 13. Noncontrolling Interest” of this Quarterly Report on Form 10-Q.

19

Segment Adjusted EBITDA. Our 2010 Quarter Segment Adjusted EBITDA increased $50.9 million, or 61.5%, to $133.7 million from the 2009 Quarter Segment Adjusted EBITDA of $82.8 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are (in thousands):

	Three Months Ended September 30,
	2010			2009			Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	114,215		$	70,090		$	44,125		63.0	%
Central Appalachia		8,307			6,517			1,790		27.5	%
Northern Appalachia		8,781			3,234			5,547		(1	)
Other and Corporate		2,370			3,189			(819	)	(25.7	)%
Elimination		—			(280	)		280		(1	)
Total Segment Adjusted EBITDA (2)	$	133,673		$	82,750		$	50,923		61.5	%
Tons sold
Illinois Basin		6,276			4,925			1,351		27.4	%
Central Appalachia		531			604			(73	)	(12.1	)%
Northern Appalachia		837			650			187		28.8	%
Other and Corporate		32			—			32		(1	)
Elimination		—			—			—		—
Total tons sold		7,676			6,179			1,497		24.2	%
Coal sales
Illinois Basin	$	299,161		$	207,410		$	91,751		44.2	%
Central Appalachia		41,481			41,357			124		0.3	%
Northern Appalachia		54,126			32,861			21,265		64.7	%
Other and Corporate		1,887			—			1,887		(1	)
Elimination		—			—			—		—
Total coal sales	$	396,655		$	281,628		$	115,027		40.8	%
Other sales and operating revenues
Illinois Basin	$	238		$	257		$	(19	)	(7.4	)%
Central Appalachia		—			—			—		—
Northern Appalachia		923			1,024			(101	)	(9.9	)%
Other and Corporate		10,814			9,487			1,327		13.9	%
Elimination		(5,293	)		(4,415	)		(878	)	(19.9	)%
Total other sales and operating revenues	$	6,682		$	6,353		$	329		5.2	%
Segment Adjusted EBITDA Expense
Illinois Basin	$	185,183		$	137,579		$	47,604		34.6	%
Central Appalachia		33,175			34,839			(1,664	)	(4.8	)%
Northern Appalachia		46,268			30,650			15,618		51.0	%
Other and Corporate		10,331			6,298			4,033		64.0	%
Elimination		(5,293	)		(4,135	)		(1,158	)	(28.0	)%
Total Segment Adjusted EBITDA Expense (3)	$	269,664		$	205,231		$	64,433		31.4	%

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

20

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

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

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

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

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

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

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

	Three Months Ended
	September 30,
	2010			2009
Segment Adjusted EBITDA	$	133,673		$	82,750
General and administrative		(14,304	)		(9,959	)
Depreciation, depletion and amortization		(37,587	)		(28,145	)
Interest expense, net		(7,586	)		(7,563	)
Income tax expense		(995	)		(586	)
Net income	$	73,201		$	36,497
Net income attributable to noncontrolling interest		—			(53	)
Net Income of ARLP	$	73,201		$	36,444

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

21

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

	Three Months Ended
	September 30,
	2010			2009
Segment Adjusted EBITDA Expense	$	269,664		$	205,231
Outside coal purchases		(5,736	)		(517	)
Other income		460			126
Operating expense (excluding depreciation, depletion and amortization)	$	264,388		$	204,840

Illinois Basin – Segment Adjusted EBITDA increased 63.0% to $114.2 million in the 2010 Quarter from $70.1 million in the 2009 Quarter. The increase of $44.1 million was primarily attributable to a 27.4% increase in tons sold to 6.3 million tons in the 2010 Quarter, as well as strong contract pricing reflecting a higher average coal sales price of $47.67 per ton sold during the 2010 Quarter compared to $42.11 per ton sold for the 2009 Quarter. Coal sales increased 44.2% to $299.2 million in the 2010 Quarter compared to $207.4 million in the 2009 Quarter. The increase of $91.8 million primarily reflects increased sales from our new River View mine (which commenced operations in August 2009 and continued to expand production during 2010). Total Segment Adjusted EBITDA Expense for the 2010 Quarter increased 34.6% to $185.2 million from $137.6 million in the 2009 Quarter and increased $1.58 per ton sold to $29.51 from $27.93 per ton sold, primarily as a result of certain cost increases described above under consolidated operating expenses, as well as ongoing production restrictions related to the failure of the vertical hoist system at the Pattiki mine and a two week production disruption at our Gibson mine due to a roof fall on the main belt line. For more information on our Pattiki mine, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 4. Pattiki Vertical Hoist Conveyor System Failure” of this Quarterly Report on Form 10-Q.

Central Appalachia – Segment Adjusted EBITDA increased 27.5% to $8.3 million for the 2010 Quarter compared to $6.5 million in the 2009 Quarter. The increase of $1.8 million was primarily attributable to strong contract pricing reflecting a higher average coal sales price of $78.18 per ton sold during the 2010 Quarter compared to $68.43 per ton sold for the 2009 Quarter, partially offset by lower sales volumes as a result of reduced production due to the impact of heightened regulatory oversight, lower clean coal recovery due to mining conditions and the continued impact of idling one mining unit at Pontiki in July 2009. Segment Adjusted EBITDA Expense per ton sold during the 2010 Quarter increased to $62.52 compared to $57.64 per ton sold in the 2009 Quarter, an increase of $4.88 per ton sold reflecting certain cost increases described above under consolidated operating expenses, as well as lower production volumes described above. Although Segment Adjusted EBITDA Expense per ton sold increased in the 2010 Quarter, Segment Adjusted EBITDA Expense for the 2010 Quarter decreased 4.8% to $33.2 million from $34.8 million in the 2009 Quarter primarily as a result of lower coal sales volumes offset in part by higher expenses per ton as described above.

Northern Appalachia – Segment Adjusted EBITDA increased to $8.8 million for the 2010 Quarter as compared to $3.2 million in the 2009 Quarter. This increase of $5.6 million was primarily attributable to strong contract pricing reflecting a higher average sales price of $64.63 per ton sold for the 2010 Quarter compared to $50.58 per ton sold for the 2009 Quarter, as well as higher tons sold which increased 28.8% to 0.8 million tons in the 2010 Quarter, both resulting from improved demand in the export coal markets, partially offset by increased coal sales of lower priced incidental production from our Tunnel Ridge development project. Total Segment Adjusted EBITDA Expense for the 2010 Quarter

22

increased 51.0% to $46.3 million from $30.7 million in the 2009 Quarter and increased $8.07 per ton sold to $55.25 from $47.18 per ton sold, primarily as a result of higher coals sales volumes, higher costs associated with producing metallurgical quality coal, lower coal recoveries due to adverse geologic conditions, as well as the other cost increases described above under consolidated operating expenses, including non-capitalized costs incurred related to our Tunnel Ridge mine development project, increased coal purchases, the resumption in February 2010 of a third-party mining operation that had been idled in May 2009 and increased production from our other third-party mining operation. Increased outside coal purchases and third-party mining production were both in response to improved demand in the export market, as noted above.

Other and Corporate – Segment Adjusted EBITDA decreased to $2.4 million in the 2010 Quarter from $3.2 million in the 2009 Quarter. The decrease of $0.8 million was primarily attributable to the impact of the deconsolidation of MAC effective January 1, 2010, lower EBITDA associated with Matrix Group safety equipment sales to our other subsidiaries (which are eliminated upon consolidation) and lower Mt. Vernon outside transloading revenues, partially offset by higher coal brokerage sales and higher EBITDA resulting from increased third-party safety equipment sales and services revenue at Matrix Design. Other sales and operating revenues increased 13.9% to $10.8 million for the 2010 Quarter compared to $9.5 million for the 2009 Quarter. The increase of $1.3 million was primarily attributable to increased services revenue and sales of mine safety equipment by the Matrix Group. Segment Adjusted EBITDA Expense increased 64.0% to $10.3 million for the 2010 Quarter, primarily due to increased expenses associated with higher services revenue and safety equipment sales by the Matrix Group and higher coal brokerage expenses.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

We reported record Net Income of ARLP of $233.7 million for the nine months ended September 30, 2010 (“2010 Period”) compared to $150.4 million for the nine months ended September 30, 2009 (“2009 Period”). This increase of $83.3 million was principally due to increased tons sold and improved contract pricing resulting in an average coal sales price of $50.86 per ton sold, as compared to $46.76 per ton sold for the 2009 Period. We had tons sold of 22.5 million and tons produced of 21.6 million for the 2010 Period compared to 18.9 million tons sold and 19.5 million tons produced for the 2009 Period. This increase in produced tons primarily reflects increased production from our new River View mine and resulted in higher operating expenses during the 2010 Period, particularly impacting materials and supplies expenses, sales-related expenses and labor and labor-related expenses. Expenses were further impacted by increased depreciation, depletion and amortization.

	Nine Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)				(per ton sold)
Tons sold		22,545		18,853		N/A		N/A
Tons produced		21,585		19,500		N/A		N/A
Coal sales	$	1,146,719	$	881,508	$	50.86	$	46.76
Operating expenses and outside coal purchases	$	762,479	$	611,402	$	33.82	$	32.43

Coal sales. Coal sales for the 2010 Period increased 30.1% to $1.1 billion from $881.5 million for the 2009 Period. The increase of $265.2 million in coal sales reflected the benefit of increased tons sold (contributing $172.7 million in coal sales) and higher average coal sales prices (contributing $92.5 million in additional coal sales). Average coal sales prices increased $4.10 per ton sold to $50.86 per ton in the 2010 Period as compared to the 2009 Period, primarily as a result of improved contract pricing across all regions.

23

Operating expenses. Operating expenses increased 23.9% to $750.4 million for the 2010 Period from $605.7 million for the 2009 Period primarily due to record coal sales and production volumes. Increased River View production and Tunnel Ridge development combined to increase certain operating expenses $87.0 million during the 2010 Period over the 2009 Period and are generally included in the variances discussed further below. In addition to the impact of record volumes, operating expenses were impacted by various other factors, the most significant of which are also discussed below:

• Labor and benefit expenses per ton produced, excluding workers’ compensation, decreased to $10.78 per ton in the 2010 Period from $10.90 per ton in the 2009 Period. The decrease of $0.12 per ton was primarily attributable to lower labor cost per ton resulting from production at our new River View mine and a decrease in the cost of training new employees in the Illinois Basin, partially offset by increased mine development labor at our Tunnel Ridge mine, heightened regulatory oversight, particularly at our Central Appalachian mines, and production disruptions at our Dotiki, Gibson and Pattiki mines during the 2010 Period;

• Workers’ compensation expenses per ton produced decreased to $1.10 per ton in the 2010 Period from $1.31 per ton in the 2009 Period. The decrease of $0.21 per ton produced resulted primarily from non-cash charges during the 2009 Period due to discount rate changes, which increased the accrued liabilities for the present value of estimated future claim payments, partially offset by unfavorable reserve adjustments for new claims incurred during the 2010 Period;

• Material and supplies expenses per ton produced increased 9.0% to $10.32 per ton in the 2010 Period from $9.47 per ton in the 2009 Period. The increase of $0.85 per ton produced resulted from increased costs for certain products and services, primarily outside services expenses (increase of $0.28 per ton), roof support (increase of $0.25 per ton), power and fuel used in the mining process (increase of $0.18 per ton) and rock dust (increase of $0.09 per ton);

• Maintenance expenses per ton produced decreased 2.7% to $3.56 per ton in the 2010 Period from $3.66 per ton in the 2009 Period. The decrease of $0.10 per ton produced resulted primarily from the benefit of newer equipment and increased production at our new River View mining complex, partially offset by adverse geologic conditions at our Mettiki mine and higher maintenance costs for our mine development project at Tunnel Ridge;

• Mine administration expenses increased $7.8 million for the 2010 Period compared to the 2009 Period, primarily due to higher costs resulting from increased third-party product sales by Matrix Design and increased estimated regulatory costs;

• Contract mining expenses increased $3.0 million for the 2010 Period compared to the 2009 Period. The increase primarily reflects the restart of a third-party mining operation in our Northern Appalachian region during February 2010 that was previously idled in May 2009 (due to weak demand in the export and spot coal markets) and increased production from other existing contract mining operations in Northern Appalachia, both in response to increased demand in the export coal market;

• Production taxes and royalties expenses (which were incurred as a percentage of coal sales prices and volumes) increased $0.41 per produced ton sold in the 2010 Period compared to the 2009 Period primarily as a result of increased average coal sales prices across all regions;

24

• Operating expenses per ton also increased in the 2010 Period due to 1.3 million tons sold from higher cost beginning of the year coal inventory compared to 261,000 tons sold from beginning coal inventory in the 2009 Period; and

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

General and administrative. General and administrative expenses for the 2010 Period increased to $36.6 million compared to $29.0 million in the 2009 Period. The increase of $7.6 million was primarily due to increased, incentive compensation expenses and retirement plan expense.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, products and services provided by MAC (in the 2009 Period only), Matrix Design and other outside services and administrative services revenue from affiliates. Other sales and operating revenues increased to $19.1 million for the 2010 Period from $16.0 million for the 2009 Period. The increase of $3.1 million was primarily attributable to increased Matrix Design product sales, partially offset by lower transloading revenues and decreased rock dust revenues reflecting the deconsolidation of MAC. For more information about MAC, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 13. Noncontrolling Interest” of this Quarterly Report on Form 10-Q.

Outside coal purchases. Outside coal purchases increased to $12.1 million for the 2010 Period from $5.7 million in the 2009 Period. The increase of $6.4 million was primarily attributable to an increase in outside coal purchases related to our Northern Appalachian region in response to improved demand in export coal markets as well as increased coal brokerage activity, partially offset by decreased outside coal purchases in the Central Appalachian region due to the lack of attractive sales opportunities in the coal spot markets that were available in the first quarter of 2009.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $109.6 million for the 2010 Period from $83.8 million for the 2009 Period. The increase of $25.8 million was primarily attributable to additional depreciation expense associated with our River View mine in addition to continuing capital expenditures related to infrastructure improvements and efficiency projects.

Interest expense. Interest expense, net of capitalized interest, decreased to $22.7 million for the 2010 Period from $23.5 million for the 2009 Period. The decrease of $0.8 million was principally attributable to reduced interest expense resulting from annual principal repayments made during August 2010 and 2009 of $18.0 million on our original senior notes issued in 1999, partially offset by increased interest expense for borrowings on the ARLP Credit Facility during the 2010 Period, each of which are discussed in more detail below under “–Debt Obligations.”

Interest income.Interest income decreased to $0.1 million for the 2010 Period from $1.0 million for the 2009 Period. The decrease of $0.9 million resulted from decreased interest income earned on short-term investments purchased with proceeds from the 2008 financing activities in the 2009 Period, which were substantially liquidated throughout 2009.

Transportation revenues and expenses. Transportation revenues and expenses each decreased to $25.6 million for the 2010 Period compared to $35.3 million for the 2009 Period. The decrease of $9.7 million was primarily attributable to reduced tonnage in the 2010 Period for which we arranged the

25

transportation compared to the 2009 Period, as well as a decrease in average transportation rates of $0.27 per ton in the 2010 Period compared to the 2009 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 tax expense. Income tax expense increased to $1.6 million for the 2010 Period compared to $0.8 million for the 2009 Period. The increase of $0.8 million was primarily due to differences in the forecasted annual operating income for 2010 as compared to 2009 for Matrix Design; thus, increased taxes reflect higher net income in the 2010 Period from our Matrix Design operation.

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 $0.2 million for the 2009 Period. Effective January 1, 2010, we deconsolidated MAC based on the amendments to the provisions of FASB ASC 810, Consolidation. For more information about MAC, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 13. Noncontrolling Interest” of this Quarterly Report on Form 10-Q.

26

Segment Adjusted EBITDA. Our 2010 Period Segment Adjusted EBITDA increased $117.3 million, or 40.9%, to $403.9 million from the 2009 Period Segment Adjusted EBITDA of $286.6 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are (in thousands):

	Nine Months Ended September 30,
	2010			2009			Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	344,216		$	237,860		$	106,356		44.7	%
Central Appalachia		24,141			29,486			(5,345	)	(18.1	)%
Northern Appalachia		29,892			11,571			18,321		(1	)
Other and Corporate		5,701			8,098			(2,397	)	(29.6	)%
Elimination		—			(362	)		362		(1	)
Total Segment Adjusted EBITDA (2)	$	403,950		$	286,653		$	117,297		40.9	%
Tons sold
Illinois Basin		18,465			14,950			3,515		23.5	%
Central Appalachia		1,680			1,983			(303	)	(15.3	)%
Northern Appalachia		2,368			1,920			448		23.3	%
Other and Corporate		32			—			32		(1	)
Elimination		—			—			—		—
Total tons sold		22,545			18,853			3,692		19.6	%
Coal sales
Illinois Basin	$	875,805		$	646,901		$	228,904		35.4	%
Central Appalachia		121,947			136,143			(14,196	)	(10.4	)%
Northern Appalachia		147,066			98,007			49,059		50.1	%
Other and Corporate		1,901			457			1,444		(1	)
Elimination		—			—			—		—
Total coal sales	$	1,146,719		$	881,508		$	265,211		30.1	%
Other sales and operating revenues
Illinois Basin	$	1,038		$	1,061		$	(23	)	(2.2	)%
Central Appalachia		114			128			(14	)	(10.9	)%
Northern Appalachia		2,681			2,499			182		7.3	%
Other and Corporate		32,149			26,965			5,184		19.2	%
Elimination		(16,886	)		(14,660	)		(2,226	)	15.2	%
Total other sales and operating revenues	$	19,096		$	15,993		$	3,103		19.4	%
Segment Adjusted EBITDA Expense
Illinois Basin	$	532,626		$	410,103		$	122,523		29.9	%
Central Appalachia		97,921			106,784			(8,863	)	(8.3	)%
Northern Appalachia		119,855			88,934			30,921		34.8	%
Other and Corporate		28,349			19,325			9,024		46.7	%
Elimination		(16,886	)		(14,298	)		(2,588	)	(18.1	)%
Total Segment Adjusted EBITDA Expense (3)	$	761,865		$	610,848		$	151,017		24.7	%

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

27

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

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

• the ability of our assets to generate cash sufficient to pay interest costs and support 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, the most comparable GAAP financial measures (in thousands):

	Nine Months Ended September 30,
	2010			2009
Segment Adjusted EBITDA	$	403,950		$	286,653
General and administrative		(36,633	)		(29,000	)
Depreciation, depletion and amortization		(109,560	)		(83,767	)
Interest expense, net		(22,521	)		(22,428	)
Income tax expense		(1,586	)		(811	)
Net income		233,650			150,647
Net income attributable to noncontrolling interest		—			(232	)
Net income of ARLP	$	233,650		$	150,415

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

28

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

	Nine Months Ended September 30,
	2010			2009
Segment Adjusted EBITDA Expense	$	761,865		$	610,848
Outside coal purchases		(12,122	)		(5,709	)
Other income		614			554
Operating expense (excluding depreciation, depletion and amortization)	$	750,357		$	605,693

Illinois Basin – Segment Adjusted EBITDA increased 44.7% to $344.2 million for the 2010 Period from $237.9 million for the 2009 Period. The increase of $106.3 million was primarily attributable to increased tons sold, which increased 23.5% to 18.5 million tons sold in the 2010 Period, as well as improved contract pricing resulting in a higher average coal sales price of $47.43 per ton during the 2010 Period compared to $43.27 per ton for the 2009 Period. Coal sales increased 35.4% to $875.8 million in the 2010 Period compared to $646.9 million in the 2009 Period. The increase of $228.9 million primarily reflects increased sales from our new River View mine (which commenced operations in August of 2009 and continued to expand production during the 2010 Period) and the negative impact of weather disruptions in the 2009 Period at our Dotiki, Warrior and Elk Creek mines, partially offset by production disruptions at our Dotiki, Gibson and Pattiki mines during the 2010 Period. Total Segment Adjusted EBITDA Expense for the 2010 Period increased 29.9% to $532.6 million from $410.1 million in the 2009 Period and increased $1.41 per ton sold to $28.84 from $27.43 per ton sold, primarily as a result of certain cost increases described above under consolidated operating expenses as well as a $1.2 million loss on the retirement of certain assets related to the failure of the vertical hoist conveyor system at our Pattiki mine and the aforementioned production disruptions at our Dotiki, Gibson and Pattiki mines. For more information on our Pattiki mine, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 4. Pattiki Vertical Hoist Conveyor System Failure” of this Quarterly Report on Form 10-Q.

Central Appalachia – Segment Adjusted EBITDA decreased $5.4 million, or 18.1%, to $24.1 million for the 2010 Period, compared to $29.5 million for the 2009 Period. The decrease was primarily the result of lower sales volumes due to reduced coal demand in the spot market during the 2010 Period, the impact of heightened regulatory oversight, lower clean coal recovery due to mining conditions and the continued impact of idling one mining unit at Pontiki in July 2009, partially offset by improved contract pricing in the 2010 Period that resulted in an increase in the average coal sales price of $3.94 per ton to $72.59 per ton in the 2010 Period, as compared to $68.65 per ton in the 2009 Period. Segment Adjusted EBITDA Expense per ton sold during the 2010 Period increased to $58.29 compared to $53.85 per ton sold, an increase of $4.44 per ton sold, reflecting certain cost increases described above under consolidated operating expenses, as well as the impact of lower coal sales volumes and 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. Although Segment Adjusted EBITDA Expense per ton sold increased, Segment Adjusted EBITDA Expense for the 2010 Period decreased 8.3% to $97.9 million from $106.8 million in the 2009 Period primarily as a result of lower coal sales offset in part by higher expenses per ton as described above.

Northern Appalachia – Segment Adjusted EBITDA increased to $29.9 million for the 2010 Period, compared to $11.6 million for the 2009 Period. The increase of $18.3 million was primarily

29

attributable to strong contract pricing reflecting a higher average sales price of $62.11 per ton sold for the 2010 Period compared to $51.05 per ton sold for the 2009 Period, as well as increased tons sold which increased 23.3% to 2.4 million tons in the 2010 Period, both resulting from improved demand in the export coal markets, as well as the benefit of increased production days and additional contract miner production. Segment Adjusted EBITDA Expense for the 2010 Period increased 34.8% to $119.9 million from $88.9 million in the 2009 Period and increased $4.30 on a per ton sold basis to $50.62 from $46.32 per ton sold, primarily as a result higher coal sales volumes, higher costs associated with producing metallurgical quality coal, lower coal recoveries due to adverse geologic conditions, as well as other cost increases described above under consolidated operating expenses, including non-capitalized costs incurred related to our Tunnel Ridge mine development project.

Other and Corporate – Segment Adjusted EBITDA decreased to $5.7 million in the 2010 Period from $8.1 million in the 2009 Period. The decrease of $2.4 million was primarily attributable to the impact of the deconsolidation of MAC effective January 1, 2010, lower EBITDA associated with Matrix Group safety equipment sales to our other subsidiaries (which are eliminated upon consolidation), a loss in the 2010 Period compared to a gain in the 2009 Period associated with United Kingdom (“UK”) currency previously held for future equipment purchases from a UK supplier and lower Mt. Vernon outside transloading revenues and affiliate administrative service revenues, partially offset by higher EBITDA resulting from increased third-party safety equipment sales and services revenue at Matrix Design. For more information about MAC, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 13. Noncontrolling Interest” of this Quarterly Report on Form 10-Q. Other sales and operating revenues increased 19.2% to $32.1 million for the 2010 Period compared to $27.0 million for the 2009 Period. The increase of $5.1 million was primarily attributable to increased services revenue and sales of mine safety equipment by the Matrix Group. Segment Adjusted EBITDA Expense increased 46.7% to $28.3 million for the 2010 Period, primarily due to increased expenses associated with higher services revenue and safety equipment sales by the Matrix Group, higher coal brokerage expenses associated with increased brokerage coal sales offset in part by the impact of the deconsolidation of MAC mentioned above.

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, cash generated from operations, cash from borrowings under the ARLP Credit Facility, and cash provided from the issuance of debt or equity will be sufficient to meet our working capital requirements, anticipated capital expenditures, scheduled debt payments and distribution payments. Our ability to satisfy our obligations and planned expenditures will depend upon our future operating performance and access to and cost of financing sources, which will be affected by prevailing economic conditions generally and in the coal industry specifically, which are beyond our control. Based on our recent operating results, current cash position, anticipated future cash flows and sources of financing that we expect to have available, we do not anticipate any significant liquidity constraints in the foreseeable future. However, to the extent operating cash flow or access to and cost of financing sources are materially different than expected, future liquidity may be adversely affected. Please read “Item 1A. Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2009.

Cash Flows

Cash provided by operating activities was $394.2 million for the 2010 Period compared to $238.3 million for the 2009 Period. The increase in cash provided by operating activities was principally

30

attributable to higher net income, increases in certain operating liabilities, such as accrued taxes other than income taxes, accrued payroll and related expenses and a reduction in coal inventory costs during the 2010 Period as compared to a significant increase during the 2009 Period. These increases in cash provided by operating activities were partially offset by increases in certain operating assets, such as accounts receivable.

Net cash used in investing activities was $238.1 million for the 2010 Period compared to $249.1 million for the 2009 Period. The decrease in cash used for investing activities was primarily attributable to decreased capital expenditures due to the completion of our River View mine development during the 2009 Quarter and Warrior’s infrastructure additions during the second quarter of 2009, partially offset by an increase in Tunnel Ridge capital expenditures and timing differences in accounts payable and accrued liabilities compared to the 2009 Period.

Net cash used in financing activities was $157.1 million for the 2010 Period compared to $142.7 million for the 2009 Period. The increase in cash used in financing activities was primarily attributable to increased distributions paid to partners in the 2010 Period.

Capital Expenditures

Capital expenditures decreased to $233.8 million in the 2010 Period from $251.5 million in the 2009 Period. See “—Cash Flows” above for additional information regarding capital expenditures.

Our anticipated total capital expenditures for the year ending December 31, 2010 are estimated in a range of $285 to $325 million. Management anticipates funding remaining 2010 capital requirements with cash and cash equivalents ($20.3 million as of September 30, 2010), cash flows provided by operations, borrowing available under the ARLP Credit Facility and, as necessary, by accessing the debt or equity capital markets. The availability and cost of additional capital will depend upon prevailing market conditions, the market price of our common units and several other factors over which we have limited control, as well as our financial condition and results of operations.

Debt Obligations

ARLP Credit Facility.Our Intermediate Partnership maintains the ARLP Credit Facility, a $150.0 million revolving credit facility that matures September 25, 2012. On September 30, 2009, our Intermediate Partnership entered into Amendment No. 2 (the “Credit Amendment”) to the ARLP Credit Facility. The Credit Amendment increased the annual capital expenditure limits under the ARLP Credit Facility. The new limits are $471.8 million for 2010, $350.0 million for 2011 and $250.0 million for 2012. The amount of any annual limit in excess of actual capital expenditures for that year carries forward and is added to the annual limit for the subsequent year.

At September 30, 2010, we had $11.6 million of letters of credit outstanding with $130.9 million available for borrowing under the ARLP Credit Facility. We had no borrowings outstanding under the ARLP Credit Facility as of September 30, 2010. We incur an annual commitment fee of 0.375% on the undrawn portion of the ARLP Credit Facility.

Lehman Commercial Paper, Inc. (“Lehman”), a subsidiary of Lehman Brothers Holding, Inc., held a 5%, or $7.5 million, commitment in our $150 million ARLP Credit Facility. On February 11, 2010, we gave our lenders a notice of borrowing under the ARLP Credit Facility and, in response to that notice, Lehman notified us that it would not fund its proportionate share of the borrowing. As a result, as of February 11, 2010, Lehman became a defaulting lender and on October 6, 2010, was removed as a commitment holder under the ARLP Credit Facility. Consequently, availability for borrowing under the ARLP Credit Facility was reduced by $7.5 million.

31

Senior Notes.Our Intermediate Partnership has $72.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in four 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.

We incurred debt issuance costs of approximately $0.3 million in 2009 associated with the ARLP Credit Facility, 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 Series A and Series B 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 the following: (i) debt to cash flow ratio of not more than 3.0 to 1.0, (ii) cash flow to interest expense ratio of not less than 4.0 to 1.0, in each case, during the four most recently ended fiscal quarters and (iii) maximum annual capital expenditures, excluding acquisitions, of $471.8 million for the year ending December 31, 2010. The debt to cash flow ratio and cash flow to interest expense ratio were 0.77 to 1.0 and 17.5 to 1.0, respectively, for the trailing twelve months ended September 30, 2010. Actual capital expenditures were $233.8 million for the 2010 Period. We were in compliance with the covenants of the ARLP Debt Arrangements as of September 30, 2010.

Other.In addition to the letters of credit available under the ARLP Credit Facility discussed above, we also have agreements with two banks to provide additional letters of credit in an aggregate amount of $31.1 million to maintain surety bonds to secure certain asset retirement obligations and our obligations for workers’ compensation benefits. At September 30, 2010, we had $30.7 million in letters of credit outstanding under agreements with these two banks. SGP guarantees $5.0 million of these outstanding letters of credit.

Related-Party Transactions

We have continuing related-party transactions with our managing general partner, AHGP and SGP and its affiliates. These related-party transactions relate principally to the provision of administrative services to AHGP and Alliance Resource Holdings II, Inc. (“ARH II”) and their respective affiliates, a time sharing agreement concerning use of aircraft and mineral and equipment leases with SGP and its affiliates, and guarantees from SGP for certain letters of credit.

MAC has a $1.75 million Revolving Credit Agreement (“Revolver”) with ARLP. On November 17, 2009, MAC entered into Amendment No. 2, effective June 30, 2009, which increased the Revolver to

32

$1.75 million from $1.5 million. The Revolver is scheduled to expire on December 31, 2010. At September 30, 2010, MAC owed ARLP $1.7 million under the Revolver, which is classified as Due from Affiliates on our condensed consolidated balance sheets.

On April 1, 2010, effective January 1, 2010, ARLP entered into an Amended and Restated Administrative Services Agreement (the “Agreement”) with our managing general partner, our Intermediate Partnership, AHGP and its general partner AGP, and ARH II, the indirect parent of SGP. The Agreement supersedes the Administrative Services Agreement signed in connection with the AHGP initial public offering in 2006. Under the Agreement, certain employees, including some executive officers, provide administrative services to AHGP and ARH II and their respective affiliates. We are reimbursed for services rendered by our employees on behalf of these affiliates as provided under the Agreement.

In August 2010, the coal lease agreement between Tunnel Ridge and SGP was amended to include additional coal reserves in the Pittsburgh No. 8 coal seam located in Ohio County, West Virginia and Washington County, Pennsylvania. This lease amendment added approximately 33.0 million tons of clean recoverable coal reserves to the proven and probable categories.

Because the Agreement and the Tunnel Ridge amendment described above were related-party transactions, they were reviewed by the board of directors of our managing general partner and its conflicts committee. Based upon this review, the conflicts committee determined that these transactions reflected market clearing terms and conditions. As a result, the board of directors of our managing general partner and its conflicts committee approved the transactions as fair and reasonable to us and our limited partners.

Please read our Annual Report on Form 10-K for the year ended December 31, 2009, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Related-Party Transactions” for additional information concerning related-party transactions.

New Accounting Standards

New Accounting Standards Issued and Adopted

In December 2009, the FASB issued Accounting Standards Update (“ASU”) 2009-17,Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities (“ASU 2009-17”). ASU 2009-17 codified Statement of Financial Accounting Standards No. 167,Amendments to FASB Interpretation No. 46(R)),which changed the consolidation guidance applicable to a variable interest entity (“VIE”). ASU 2009-17 updated the guidance governing the determination of whether an enterprise is the primary beneficiary of a VIE, and is, therefore, required to consolidate such VIE, by requiring a qualitative analysis rather than a quantitative analysis. The qualitative analysis includes, among other things, consideration of whether the enterprise has the power to direct the activities of the entity that most significantly impact the entity’s economic performance and has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. ASU 2009-17 also requires continuous reassessments of whether an enterprise is the primary beneficiary of a VIE. Previously, FASB ASC 810,Consolidation, 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, are now subject to the provisions of ASU 2009-17. In addition, ASU 2009-17 also requires enhanced disclosures about an enterprise’s involvement with a VIE. The provisions of ASU 2009-17 were effective as of the beginning of interim and annual reporting periods that began after November 15, 2009. Based on our evaluation of ASU 2009-17, we deconsolidated Mid-America Carbonates, LLC (“MAC”) upon adoption, effective January 1, 2010. For more information about MAC, please read “Part I. Item 1. Financial Statements

33

(Unaudited) – Note 13. Noncontrolling Interest” of this Quarterly Report on Form 10-Q. The deconsolidation of MAC did not have a material impact on our condensed consolidated financial statements.

In January 2010, the FASB issued ASU 2010-06,Improving Disclosures About Fair Value Measurements(“ASU 2010-06”). ASU 2010-06 amended guidance on certain aspects of FASB ASC 820,Fair Value Measurements and Disclosures,to add new requirements for disclosures of transfers into and out of Level 1 and 2 measurements and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements, all on a gross basis. ASU 2010-06 also clarifies existing fair value disclosures regarding the level of disaggregation and the inputs and valuation techniques used to measure fair value. The provisions of ASU 2010-06 were effective for the first reporting period beginning after December 15, 2009, except for the requirement to provide Level 3 activity of purchases, sales, issuances, and settlements on a gross basis, which will be effective for fiscal years beginning after December 15, 2010. The adoption of ASU 2010-06 did not have an impact on our condensed consolidated financial statements.

Other

Pattiki Vertical Hoist Conveyor System Failure

On May 13, 2010, White County Coal’s Pattiki mine was temporarily idled following the failure of the vertical hoist conveyor system used in conveying raw coal out of the mine. On July 19, 2010, White County Coal’s efforts to repair the vertical hoist conveyor system had progressed sufficiently to allow resumption of limited production operations. Our operating expenses for the nine months ended September 30, 2010 includes $1.2 million for retirement of certain assets related to the failed vertical hoist conveyor system in addition to other repair and clean-up expenses that were not significant on a consolidated or segment basis. We are conducting a final review of our commercial property (including business interruption) insurance policies, which at the time of the equipment failure provided for self-retention, various deductibles and 22% co-insurance for the first $50 million in coverage. As the loss on the vertical hoist conveyor system did not exceed our deductible for property damage, we currently believe recovery is unlikely under such policies.

While the Pattiki mine was temporarily idled, we expanded coal production at our other coal mines in the region, including the addition of the seventh and eighth production units at the River View mine, to partially offset the loss of production from the Pattiki mine. Consequently, the temporary idling of the Pattiki mine did not have a material adverse impact on our results of operations and cash flows. On July 19, 2010, the Pattiki mine resumed limited production while White County Coal continues to assess the effectiveness and reliability of the repaired vertical hoist conveyor system until such time it determines the system can be operated at full capacity. We are now operating six unit shifts at Pattiki and plan to add two more unit shifts during the quarter ending December 31, 2010, bringing Pattiki back to full capacity by the end of the year.

Insurance

During September 2010, we completed our annual property and casualty insurance renewal with various insurance coverages effective October 1, 2010. The aggregate maximum limit in the commercial property program is $75.0 million per occurrence excluding a $1.5 million deductible for property damage, a 60-day waiting period for business interruption and a $10.0 million overall aggregate deductible. The aforementioned property and casualty insurance coverages, effective October 1, 2010, replaced our prior year 14.7% participation rate with the deductibles mentioned above. We can make no assurances that we will not experience significant insurance claims in the future that could have a material adverse effect on our business, financial condition, results of operations and ability to purchase property insurance in the future.

34

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 principally to reflect changes in specified price indices or items such as taxes, royalties or actual production costs.

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. During 2009, we entered into a contract to purchase longwall shields for our Tunnel Ridge mine from a foreign supplier for approximately £10.2 million. We have paid £10.2 million to this foreign supplier through September 30, 2010, thus fulfilling our obligation. 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 at September 30, 2010.

As of September 30, 2010, the estimated fair value of the Senior Notes and Series A and Series B Senior Notes was approximately $482.1 million. The fair values of long-term debt are estimated using discounted cash flow analyses, based upon our current incremental borrowing rates for similar types of borrowing arrangements as of September 30, 2010. 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, 2009.

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 September 30, 2010. 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 September 30, 2010, 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.

35

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;

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

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

• the impact of recent federal health care legislation;

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

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

• weakness in global economic conditions or in industries in which our customers operate;

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

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

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

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

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

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

• our productivity levels and margins earned on our coal sales;

• greater than expected increases in raw material costs;

• greater than expected shortage of skilled labor;

• our ability to maintain satisfactory relations with our employees;

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

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

• greater than expected environmental regulation, costs and liabilities;

• a variety of operational, geologic, permitting, labor and weather-related factors;

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

• results of litigation, including claims not yet asserted;

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

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

36

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

• replacement of coal reserves;

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

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

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

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

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

• this Quarterly Report on Form 10-Q;

• other reports filed by us with the SEC;

• our press releases; and

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

37

PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The information in Note 3. Contingencies to the Unaudited Condensed Consolidated Financial Statements included in “Part I. Item 1. Financial Statements (Unaudited)” of this Quarterly Report on Form 10-Q herein is hereby incorporated by reference. See also “Item 3. Legal Proceedings” of the Annual Report on Form 10-K for the year ended December 31, 2009 and “Part II. Item 1. Legal Proceedings” of the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010.

On April 24, 2006, we were served with a complaint from Mr. Ned Comer, et al. (the “Plaintiffs”) alleging that approximately 40 oil and coal companies, including us, (the “Defendants”) are liable to the Plaintiffs for tortuously causing damage to Plaintiffs’ property in Mississippi. The Plaintiffs allege that the Defendants’ greenhouse gas emissions caused global warming and resulted in the increase in the destructive capacity of Hurricane Katrina. On August 30, 2007, the trial court dismissed the Plaintiffs’ complaint. On September 17, 2007, Plaintiffs filed a notice of appeal of that dismissal to the U.S. Court of Appeals for the Fifth Circuit. On October 16, 2009, the Fifth Circuit overturned the trial court’s dismissal of the Plaintiffs’ private nuisance, trespass and negligence claims, finding Article III constitutional standing and no political question. The Fifth Circuit remanded these claims to the trial court for further proceedings. By order filed February 26, 2010, the Fifth Circuit granted the Defendants’ petition for rehearing en banc, with oral argument scheduled for May 24, 2010. On May 28, 2010, the Fifth Circuit Court of Appeals dismissed the appeal because the court did not have a quorum after one of the judges hearing the appeal recused herself. The court ruled that, without a quorum, it could not decide the appeal nor could it reinstate the earlier ruling by a three judge panel that would have reversed the District Courts decision dismissing the case. On August 26, 2010, Plaintiffs petitioned the U.S. Supreme Court seeking a Writ of Mandamus ordering the Fifth Circuit to reinstate the appeal. Defendants’ response to the petition is due November 24, 2010. We believe this complaint is without merit and we do not believe that an adverse decision in this litigation matter, if any, based on our status as a defendant, will have a material adverse effect on our business, financial position or results of operations. If, however, tort claims brought in this and other cases against corporate defendants for liability arising from greenhouse gas emissions are successful, demand for our coal could be adversely impacted.

ITEM 1A. RISK FACTORS

We are subject to a variety of risks, including, but not limited to those referenced under the heading “Health Care Reform” of “Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Quarterly Report on Form 10-Q and those referenced herein to other Items contained in our Annual Report on Form 10-K for the year ended December 31, 2009, including “Item 1. Business”, “Item 1A. Risk Factors”, “Item 3. Legal Proceedings” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Except as set forth under “—Health Care Reform” and elsewhere under “Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Quarterly Report on Form 10-Q, we do not believe there have been any material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009 and our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010, except as follows.

38

Recent legislation regarding health care may adversely impact our results of operations.

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

The Health Care Act has both short-term and long-term implications on benefit plan eligibility, coverage requirements, and benefit standards and limitations. In the short term, our health care costs are expected to increase due to raising the maximum age and easing of eligibility limitations for covered dependents. The Health Care Act also prevents the group health plan from limiting benefit payments for participants who meet or exceed annual or lifetime dollar limits per covered individual. We do not currently expect raising the maximum age and easing of eligibility limitations for covered dependents to significantly increase our annual health care costs beginning in 2011. In addition, we currently expect removing the lifetime maximum to have an additional impact on us that we are unable to reasonably estimate at this time. While historically few participants have reached the plan lifetime maximum limit of $1 million, future federal and state mandates are expected to impact large claims costs and make this a potentially greater risk variable in the future. In the long term, our plan’s health care costs are expected to increase for various reasons due to the Health Care Act, including the potential impact of an excise tax on “high cost” plans (beginning in 2018), among other standard requirements. We have chosen not to “grandfather” our health care plan as allowed under the Health Care Act. Maintaining “grandfather” status prevents the plan from making plan benefit modifications that encourage participants to use high value, lower cost medical care options such as on-site medical services, generic preferred medications, and urgent care centers instead of emergency rooms.

We anticipate that certain government agencies will provide additional regulations or interpretations concerning the application of the Health Care Act and reporting required thereunder. Until these regulations or interpretations are published, we are unable to reasonably estimate the further impact of such federal mandate requirements on our future health care costs.

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

Recent health care legislation has generally made it easier for claimants to assert and prosecute Black Lung claims, which could increase our exposure to Black Lung benefit liabilities.

The recently enacted Health Care Act includes a Black Lung provision that creates a rebuttable presumption that a miner with at least 15 years of service, with totally disabling pulmonary or respiratory lung impairment and negative radiographic chest x-ray evidence, would be disabled due to pneumoconiosis and be eligible for Black Lung benefits. The new Health Care Act also makes it easier for widows of miners to become eligible for benefits, as it amended previous legislation related to coal workers’ Black Lung benefits by providing automatic extensions of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims, effective for claims filed or pending after January 1, 2005. As a result of this new legislation, the number of claimants who are awarded benefits and our future payments of Black Lung benefits could increase, which may have an adverse impact on our results of operations and cash flows.

39

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. RESERVED

ITEM 5. OTHER INFORMATION

Federal Mine Safety and Health Act Information

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

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

Our industry is focused on improving employee safety and its safety performance is continuously monitored, including through the mining industry standard of “non-fatal days lost”, or “NFDL”, which reflects both the frequency and severity of injuries incurred and, we believe, is a better measure of safety performance than compliance statistics. As indicated in the chart below, these efforts have resulted in significant safety improvements as the industry average NFDL, as reported^(a) by the Mine Safety and Health Administration (“MSHA”), has decreased approximately 60% since 1998.

40

(a) Data compiled for all U.S. underground bituminous coal mines and related surface facilities from the MSHA report “Mine Injury and Worktime, Quarterly Closeout Edition.” Data for 1998 through 2009 reflects the “January – December, Final” report for each year. Data for 2010 reflects the “January – June, Preliminary” report for the first six months of 2010.

During this same time period, the combined NFDL rating of our operating subsidiaries has averaged approximately one-third better than the industry average. The average NFDL rating of our operating subsidiaries through September 30, 2010 has positioned us to achieve our best annual NFDL results in our history.

Our mining operations are subject to extensive and stringent compliance standards established pursuant to the Federal Mine Safety and Health Act of 1977, as amended by the Federal Mine Improvement and New Emergency Response Act of 2006 (as amended, the “Mine Act”). MSHA monitors and rigorously enforces compliance with these standards, and our mining operations are inspected frequently. During the three months ended September 30, 2010, our mines were subject to 1,598 MSHA inspection days, with an average of only 0.19 “significant and substantial”, or “S&S”, citations written per inspection day.

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

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

41

We take all allegations of violations of Mine Act standards seriously, and if we disagree with the assertions of an MSHA inspector, we exercise our right to challenge those findings by “contesting” the citation or order pursuant to the procedures established by the Mine Act and its regulations. During 2010, our operating subsidiaries have contested approximately 25% of all citations and the majority of S&S citations issued by MSHA inspectors. These contest proceedings frequently result in the dismissal or modification of previously issued citations, substantial reductions in the penalty amounts originally assessed by MSHA, or both.

The recently enacted Dodd-Frank Act requires issuers to include in periodic reports filed with the SEC certain information relating to citations or orders for violations of standards under the Mine Act. Responding to that legislation, we report that, for the three months ended September 30, 2010, none of our operating subsidiaries (a) received any violations under section 110(b)(2) of the Mine Act for failure to make reasonable efforts to eliminate a known violation of a mandatory safety or health standard that substantially proximately caused, or reasonably could have been expected to cause, death or serious bodily injury, (b) received any MSHA written notice under Mine Act section 104(e) of a pattern of violations of mandatory health or safety standards or the potential to have such a pattern, (c) had any fatalities or (d) had any legal proceedings (i.e. appeals before the Federal Mine Safety and Health Review Commission (the “Commission”)) pending. We have 264 contests pending before administrative law judges of the Commission that were initiated during the quarter and that involve all types of citations (i.e., not just S&S citations).

The following chart sets out additional information responding to the Dodd-Frank Act for the three months ended September 30, 2010:

Subsidiary Name (1)	Section 104(a) Citations (2)		Section 104(b) Orders (3)		Section  104(d) Citations and Orders (4)		Section 107(a) Orders (5)		Total  Proposed Assessments (in thousands) (6)
Illinois Basin Operations
Webster County Coal, LLC (KY)		51		—		3		—	$	103.3
Warrior Coal, LLC (KY)		61		—		1		—	$	28.6
Hopkins County Coal, LLC (KY)		30		—		—		—	$	17.5
River View Coal, LLC (KY)		22		—		—		—	$	2.3
White County Coal, LLC (IL)		8		—		1		—	$	—
Gibson County Coal, LLC (IN)		33		—		1		—	$	33.7
Central Appalachian Operations
Pontiki Coal, LLC (KY)		29		—		1		—	$	52.6
MC Mining, LLC (KY)		28		2		—		—	$	50.9
Northern Appalachian Operations
Mettiki Coal, LLC (MD)		1		—		—		—	$	0.3
Mettiki Coal (WV), LLC		27		—		—		—	$	4.3
Tunnel Ridge, LLC (PA/WV)		10		—		—		—	$	1.0

⁽¹⁾ The statistics reported for each of our subsidiaries listed above include all components of the mining complex involved and therefore may involve multiple MSHA identification numbers. Any S&S citations or orders issued to our subsidiary, Excel Mining, LLC, are included in the statistics for either Pontiki Coal, LLC or MC Mining, LLC, depending on the mining complex involved.

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

42

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

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

⁽⁵⁾ Mine Act section 107(a) orders are for alleged conditions or practices which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated.

⁽⁶⁾ Amounts shown include assessments proposed by MSHA during the three months ended September 30, 2010 on the citations and orders reflected in this chart.

43

ITEM 6. EXHIBITS

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File No.  and Film No.	Exhibit	Filing Date	Filed Herewith*
31.1	Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated November 8, 2010, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					þ
31.2	Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated November 8, 2010, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					þ
32.1	Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated November 8, 2010, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.					þ
32.2	Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated November 8, 2010, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.					þ
101	Interactive Data File (Form 10-Q for the quarter ended September 30, 2010 furnished in XBRL). The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed” and, in accordance with Rule 406T of Regulation S-T, is not deemed “filed” or part of a registration statement or prospectus for purposes of Sections 11 and 12 of the Securities Act of 1933, as amended, and Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under these sections.

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

44

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, in Tulsa, Oklahoma, on November 8, 2010.

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

45