UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2011

OR

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

For the transition period from                      to                     

Commission File No.: 0-26823

ALLIANCE RESOURCE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware	73-1564280
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

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

(Address of principal executive offices and zip code)

(918) 295-7600

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    x  Yes    ¨  No

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

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

Large Accelerated Filer	x	Accelerated Filer	¨
Non-Accelerated Filer	¨  (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    x  No

As of August 8, 2011, 36,775,741 common units are outstanding.

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION

		Page
ITEM 1.	Financial Statements (Unaudited)
	ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
	Condensed Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010		1
	Condensed Consolidated Statements of Income for the three and six months ended June 30, 2011 and 2010		2
	Condensed Consolidated Statements of Cash Flows for six months ended June 30, 2011 and 2010		3
	Notes to Condensed Consolidated Financial Statements		4
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		16
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk		34
ITEM 4.	Controls and Procedures		35
	Forward-Looking Statements		36

PART II

OTHER INFORMATION

ITEM 1.	Legal Proceedings
ITEM 1A.	Risk Factors	38
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
ITEM 3.	Defaults upon Senior Securities	38
ITEM 4.	Reserved	38
ITEM 5.	Other Information	38
ITEM 6.	Exhibits	42

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PART I

FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)

	June 30,			December 31,
	2011			2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	347,111		$	339,562
Trade receivables		145,826			112,942
Other receivables		1,314			2,537
Due from affiliates		264			1,912
Inventories		52,081			31,548
Advance royalties		4,812			4,812
Prepaid expenses and other assets		4,100			10,024
Total current assets		555,508			503,337
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost		1,730,668			1,598,130
Less accumulated depreciation, depletion and amortization		(711,207	)		(648,883	)
Total property, plant and equipment, net		1,019,461			949,247
OTHER ASSETS:
Advance royalties		30,684			27,439
Other long-term assets		20,357			21,255
Total other assets		51,041			48,694
TOTAL ASSETS	$	1,626,010		$	1,501,278
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	79,683		$	63,339
Due to affiliates		467			573
Accrued taxes other than income taxes		18,754			13,901
Accrued payroll and related expenses		30,848			30,773
Accrued interest		3,403			2,491
Workers’ compensation and pneumoconiosis benefits		8,357			8,518
Current capital lease obligations		771			295
Other current liabilities		17,893			16,715
Current maturities, long-term debt		18,000			18,000
Total current liabilities		178,176			154,605
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities		704,000			704,000
Pneumoconiosis benefits		47,753			45,039
Accrued pension benefit		10,809			13,296
Workers’ compensation		66,785			59,796
Asset retirement obligations		56,880			56,045
Due to affiliates		—			1,954
Long-term capital lease obligations		2,835			165
Other liabilities		3,592			10,595
Total long-term liabilities		892,654			890,890
Total liabilities		1,070,830			1,045,495
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
Alliance Resource Partners, L.P. (“ARLP”) Partners’ Capital:
Limited Partners - Common Unitholders 36,775,741 and 36,716,855 units outstanding, respectively		857,015			761,875
General Partners’ deficit		(283,247	)		(287,371	)
Accumulated other comprehensive loss		(18,588	)		(18,721	)
Total Partners’ Capital		555,180			455,783
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,626,010		$	1,501,278

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except unit and per unit data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
SALES AND OPERATING REVENUES:
Coal sales	$	442,483		$	385,905		$	850,168		$	750,064
Transportation revenues		8,706			8,821			18,006			18,526
Other sales and operating revenues		6,757			5,617			13,030			12,414
Total revenues		457,946			400,343			881,204			781,004
EXPENSES:
Operating expenses (excluding depreciation, depletion and amortization)		284,117			246,702			540,235			485,969
Transportation expenses		8,706			8,821			18,006			18,526
Outside coal purchases		5,842			4,544			9,631			6,386
General and administrative		13,002			11,628			25,422			22,329
Depreciation, depletion and amortization		39,100			35,677			76,962			71,973
Total operating expenses		350,767			307,372			670,256			605,183
INCOME FROM OPERATIONS		107,179			92,971			210,948			175,821
Interest expense (net of interest capitalized for the three and six months ended June 30, 2011 and 2010 of $167, $423, $312 and $691, respectively)		(9,156	)		(7,439	)		(18,466	)		(15,034	)
Interest income		87			48			192			99
Other income		393			304			980			154
INCOME BEFORE INCOME TAXES		98,503			85,884			193,654			161,040
INCOME TAX EXPENSE		325			423			96			591
NET INCOME	$	98,178		$	85,461		$	193,558		$	160,449
GENERAL PARTNERS’ INTEREST IN NET INCOME	$	22,209		$	17,957		$	43,214		$	34,999
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	75,969		$	67,504		$	150,344		$	125,450
BASIC NET INCOME PER LIMITED PARTNER UNIT (Note 7)	$	2.04		$	1.82		$	4.03		$	3.38
DILUTED NET INCOME PER LIMITED PARTNER UNIT (Note 7)	$	2.04		$	1.82		$	4.03		$	3.38
DISTRIBUTIONS PAID PER LIMITED PARTNER UNIT	$	0.89		$	0.79		$	1.75		$	1.565
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING - BASIC		36,775,741			36,716,855			36,762,402			36,703,901
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING - DILUTED		36,775,741			36,716,855			36,762,402			36,703,901

See notes to condensed consolidated financial statements.

2

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended June 30,
	2011			2010
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	261,385		$	258,867
CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(142,433	)		(174,848	)
Changes in accounts payable and accrued liabilities		(5,524	)		(9,913	)
Proceeds from sale of property, plant and equipment		122			102
Receipts of prior advances on Gibson rail project		810			1,032
Net cash used in investing activities		(147,025	)		(183,627	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facilities		—			66,500
Payments under revolving credit facilities		—			(61,500	)
Payments on capital lease obligations		(379	)		(160	)
Net settlement of employee withholding taxes on vesting of Long-Term Incentive Plan		(2,324	)		(1,265	)
Cash contributions by General Partners		87			43
Distributions paid to Partners		(104,195	)		(90,412	)
Net cash used in financing activities		(106,811	)		(86,794	)
EFFECT OF CURRENCY TRANSLATION ON CASH		—			(333	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		7,549			(11,887	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		339,562			21,556
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	347,111		$	9,669
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	17,433		$	15,424
Cash paid for income taxes	$	300		$	253
NON-CASH INVESTING AND FINANCING ACTIVITY:
Accounts payable for purchase of property, plant and equipment	$	18,863		$	10,905
Market value of common units issued under Long-Term Incentive Plan before minimum statutory tax withholding requirements	$	6,572		$	3,396
Assets acquired by capital lease	$	3,525		$	—

See notes to condensed consolidated financial statements.

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.

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Basis of Presentation

The accompanying condensed consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of June 30, 2011 and December 31, 2010, results of our operations for the three and six months ended June 30, 2011 and 2010 and cash flows for the six months ended June 30, 2011 and 2010. All of our intercompany transactions and accounts have been eliminated.

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

These condensed consolidated financial statements and notes are prepared pursuant to the rules and regulations of the Securities and Exchange Commission for interim reporting and should be read in conjunction with the consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2010.

Use of Estimates

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

2. NEW ACCOUNTING STANDARDS

New Accounting Standards Issued and Adopted

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

New Accounting Standards Issued and Not Yet Adopted

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

5

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

3. CONTINGENCIES

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

4. PATTIKI VERTICAL HOIST CONVEYOR SYSTEM FAILURE IN 2010

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

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

5. FAIR VALUE MEASUREMENTS

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

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

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

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

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

The carrying amounts for cash equivalents, accounts receivable and accounts payable approximate fair value because of the short maturity of those instruments. At June 30, 2011 and December 31, 2010, the

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estimated fair value of our long-term debt, including current maturities, was approximately $767.9 million and $809.5 million, respectively, based on interest rates that we believe are currently available to us for issuance of debt with similar terms and remaining maturities (Note 6).

6. LONG-TERM DEBT

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

	June 30, 2011			December 31, 2010
Credit facility	$	—		$	—
Senior notes		72,000			72,000
Series A senior notes		205,000			205,000
Series B senior notes		145,000			145,000
Term loan		300,000			300,000
		722,000			722,000
Less current maturities		(18,000	)		(18,000	)
Total long-term debt	$	704,000		$	704,000

On December 29, 2010, our Intermediate Partnership entered into a term loan agreement (the “Term Loan Agreement”) with various financial institutions for a term loan (the “Term Loan”) in the aggregate principal amount of $300 million. The Term Loan bears interest at a variable rate plus an applicable margin which fluctuates depending upon whether we elect the Term Loan (or a portion thereof) to bear interest at the Base Rate or the Eurodollar Rate (as defined in the Term Loan Agreement). We have elected the Eurodollar Rate which, with applicable margin, was 2.3% as of June 30, 2011. Interest is payable quarterly with principal due as follows: $15 million due per quarter beginning March 31, 2013 through December 31, 2013, $18.75 million due per quarter beginning March 31, 2014 through September 30, 2015 and the balance of $108.75 million due on December 31, 2015. We have the option to prepay the Term Loan at any time in whole or in part subject to terms and conditions described in the Term Loan Agreement. Upon a “change of control” (as defined in the Term Loan Agreement), the unpaid principal amount of the Term Loan, all interest thereon and all other amounts payable under the Term Loan Agreement will become due and payable.

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

Our Intermediate Partnership has a $142.5 million revolving credit facility (the “ARLP Credit Facility”), $72.0 million in senior notes (“Senior Notes”), $205.0 million in Series A and $145.0 million in Series B senior notes (the “2008 Senior Notes”) and the $300 million Term Loan (collectively, the “ARLP Debt Arrangements”), which are guaranteed by all of the direct and indirect subsidiaries of our Intermediate Partnership. The ARLP Debt Arrangements contain various covenants affecting our Intermediate Partnership and its subsidiaries restricting, among other things, the amount of distributions by our Intermediate Partnership, the incurrence of additional indebtedness and liens, the sale of assets, the making of investments, the entry into mergers and consolidations and the entry into transactions with affiliates, in each case subject to various exceptions. The ARLP Debt Arrangements also require the Intermediate Partnership to remain in control of a certain amount of mineable coal reserves relative to its annual production. In addition, the ARLP Debt Arrangements require our Intermediate Partnership to maintain the following: (a) debt to cash flow ratio of not more than 3.0 to 1.0 and (b) cash flow to interest expense ratio of not less than 4.0 to 1.0, in both cases, during the four most recently ended fiscal quarters.

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The ARLP Credit Facility, Senior Notes and the 2008 Senior Notes limit our Intermediate Partnership’s maximum annual capital expenditures, excluding acquisitions. The amount of any annual limit in excess of actual capital expenditures for that year carries forward and is added to the annual limit of the subsequent year. As a result, the capital expenditure limit for 2011 is approximately $531.9 million. The debt to cash flow ratio and cash flow to interest expense ratio were 1.33 to 1.0 and 16.2 to 1.0, respectively, for the trailing twelve months ended June 30, 2011. Actual capital expenditures were $142.4 million for the six months ended June 30, 2011. We were in compliance with the covenants of the ARLP Debt Arrangements as of June 30, 2011.

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

7. NET INCOME PER LIMITED PARTNER UNIT

We apply the provisions of FASB ASC 260, Earnings Per Share (“FASB ASC 260”), which require the two-class method in calculating basic and diluted earnings per unit (“EPU”). Net income is allocated to the general partners and limited partners in accordance with their respective partnership percentages, after giving effect to any special income or expense allocations, including incentive distributions to our managing general partner, the holder of the IDR pursuant to our partnership agreement, which are declared and paid following the end of each quarter. Under the quarterly IDR provisions of our partnership agreement, our managing general partner is entitled to receive 15% of the amount we distribute in excess of $0.275 per unit, 25% of the amount we distribute in excess of $0.3125 per unit, and 50% of the amount we distribute in excess of $0.375 per unit. Our partnership agreement contractually limits our distributions to available cash; therefore, undistributed earnings of the ARLP Partnership are not allocated to the IDR holder. In addition, our outstanding awards under our Long-Term Incentive Plan (“LTIP”), Supplemental Executive Retirement Plan (“SERP”) and the MGP Amended and Restated Deferred Compensation Plan for Directors (“Deferred Compensation Plan”) include rights to nonforfeitable distributions or distribution equivalents and are therefore considered participating securities. As such, we allocate undistributed and distributed earnings to these outstanding awards in our calculation of EPU.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Net income	$	98,178		$	85,461		$	193,558		$	160,449
Adjustments:
General partner’s priority distributions		(20,658	)		(16,579	)		(40,146	)		(32,439	)
General partners’ 2% equity ownership		(1,551	)		(1,378	)		(3,068	)		(2,560	)
Limited partners’ interest in Net Income		75,969			67,504			150,344			125,450
Less:
Distributions to participating securities		(491	)		(308	)		(961	)		(608	)
Undistributed earnings attributable to participating securities		(591	)		(384	)		(1,191	)		(674	)
Net income available to limited partners	$	74,887		$	66,812		$	148,192		$	124,168
Weighted average limited partner units outstanding – Basic and Diluted		36,776			36,717			36,762			36,704
Basic and Diluted Net Income per limited partner unit (1)	$	2.04		$	1.82		$	4.03		$	3.38

(1) Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. For the three and six months ended June 30, 2011, LTIP, SERP and Deferred Compensation Plan units of 392,719 and 400,626, respectively, were considered anti-dilutive. For the three and six months ended June 30, 2010, LTIP units of 210,328 and 206,988, respectively, were considered anti-dilutive.

8. WORKERS’ COMPENSATION AND PNEUMOCONIOSIS

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Beginning balance	$	70,965		$	66,371		$	67,687		$	63,220
Accruals increase		5,557			5,005			11,114			9,811
Payments		(2,801	)		(2,293	)		(6,028	)		(4,818	)
Interest accretion		794			833			1,587			1,666
Valuation loss		—			134			155			171
Ending balance	$	74,515		$	70,050		$	74,515		$	70,050

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Pneumoconiosis

The Patient Protection and Affordable Care Act, which was signed into law by President Obama on March 23, 2010, amended previous legislation related to coal workers’ pneumoconiosis, or black lung, providing automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims. The impact of these changes to our current population of beneficiaries and claimants resulted in an estimated $8.3 million increase to our black lung obligation at December 31, 2010. We recorded this estimate as an increase to our black lung liability and a decrease to our actuarial gain included in accumulated other comprehensive income on our December 31, 2010 condensed consolidated balance sheet. This increase to our obligation excludes the impact of potential re-filing of closed claims and potential filing rates for employees who terminated more than seven years ago as we do not have sufficient information to determine what, if any, claims will be filed until regulations are issued. We will continue to evaluate the impact of these changes on such claims and record any necessary changes in the period in which the impact is estimable. For more information, please read “Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Other—Health Care Reform” of this Quarterly Report on Form 10-Q.

9. COMPENSATION PLANS

Long-Term Incentive Plan

We have the LTIP for certain employees and officers of our managing general partner and its affiliates who perform services for us. The LTIP awards are grants of non-vested “phantom” or notional units, which upon satisfaction of vesting requirements, entitle the LTIP participant to receive ARLP common units. Annual grant levels and vesting provisions for designated participants are recommended by our President and Chief Executive Officer, subject to review and approval of the compensation committee of the MGP board of directors (“Compensation Committee”). On January 25, 2011, the Compensation Committee determined that the vesting requirements for the 2008 grants of 91,100 units (which are net of 2,500 forfeitures) had been satisfied as of January 1, 2011. As a result of this vesting, on February 11, 2011, we issued 58,886 unrestricted common units to LTIP participants. The remaining units were settled in cash to satisfy the individual tax withholding obligations for the LTIP participants. On January 25, 2011, the Compensation Committee authorized additional grants of up to 110,000 restricted units, of which 108,416 were granted during the six months ended June 30, 2011, all of which will vest on January 1, 2014 subject to satisfaction of certain financial tests. The fair value of these 2011 grants is equal to the intrinsic value at the date of grant, which was $66.84 per unit. LTIP expense was $1.4 million and $1.0 million for the three months ended June 30, 2011 and 2010, respectively, and $2.5 million and $1.9 million for the six months ended June 30, 2011 and 2010, respectively. After consideration of the January 1, 2011 vesting and subsequent issuance of 58,886 common units, approximately 2.2 million units remain available for issuance under the LTIP in the future, assuming all grants issued in 2009, 2010 and 2011 currently outstanding are settled with common units and no future forfeitures occur.

As of June 30, 2011, there was $9.2 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 June 30, 2011, the intrinsic value of the non-vested LTIP grants was $29.9 million. As of June 30, 2011, the total obligation associated with the LTIP was $6.8 million and is included in the partners’ capital-limited partners line item in our condensed consolidated balance sheets.

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

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SERP and Directors Deferred Compensation Plan

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

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

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

Amounts that were payable under either the SERP or Deferred Compensation Plan on or prior to January 1, 2011, were paid in either cash or common units of ARLP. Effective for amounts that become payable after January 1, 2011, both the Deferred Compensation Plan and the SERP require that vested benefits be paid to participants only in common units of ARLP, and therefore the phantom units now qualify for equity award accounting treatment. As a result, we reclassified a total of $9.2 million of obligations for the SERP and the Deferred Compensation Plan from due to affiliates and other long-term liabilities to partners’ capital in our condensed consolidated balance sheets as required under FASB ASC 718, Compensation-Stock Compensation, on January 1, 2011. For the six months ended June 30, 2011 and 2010, SERP and Deferred Compensation Plan participant notional account balances were credited with a total of 5,898 and 6,283 phantom units, respectively, and the fair value of these phantom units was $71.96 and $44.97, respectively, on a weighted-average basis. Total SERP and Deferred Compensation Plan expense was approximately $0.2 million and $0.6 million for the three months ended June 30, 2011 and 2011, respectively, and $0.4 million and $0.6 million for the six months ended June 30, 2011 and 2010, respectively.

As of June 30, 2011, there were 146,143 total phantom units outstanding under the SERP and Deferred Compensation Plan and the total intrinsic value of the SERP and Deferred Compensation Plan phantom units was $11.3 million. As of June 30, 2011, the total obligation associated with the SERP and Deferred Compensation Plan was $9.6 million and is included in the partners’ capital-limited partners line item in our condensed consolidated balance sheets.

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10. COMPONENTS OF PENSION PLAN NET PERIODIC BENEFIT COSTS

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Service cost	$	618		$	713		$	1,236		$	1,426
Interest cost		788			840			1,576			1,679
Expected return on plan assets		(973	)		(924	)		(1,945	)		(1,846	)
Amortization of net loss		122			269			244			538
Net periodic benefit cost	$	555		$	898		$	1,111		$	1,797

We previously disclosed in our financial statements for the year ended December 31, 2010 that we expected to contribute $5.0 million to the Pension Plan in 2011. During the six months ended June 30, 2011, we made contribution payments of $2.6 million for the 2010 plan year and $0.8 million for the 2011 plan year. On July 15, 2011, we made a payment of $0.8 million for the 2011 plan year. We will make an additional quarterly contribution of $0.8 million for the 2011 plan year and, therefore, we expect to contribute a total of approximately $5.0 million to the Pension Plan in 2011 for the 2010 and 2011 plan years.

11. COMPREHENSIVE INCOME

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Net income	$	98,178	$	85,461	$	193,558	$	160,449
Other comprehensive income:
Actuarially determined long-term liability adjustments		67		269		133		538
Total other comprehensive income		67		269		133		538
Comprehensive income	$	98,245	$	85,730	$	193,691	$	160,987

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

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12. SEGMENT INFORMATION

We operate in the eastern U.S. as a producer and marketer of coal to major utilities and industrial users. We aggregate multiple operating segments into four reportable segments: Illinois Basin, Central Appalachia, Northern Appalachia and Other and Corporate. The first three reportable segments correspond to the three major coal producing regions in the eastern U.S. Factors similarly affecting financial performance of our operating segments within each of these three reportable segments include coal quality, coal seam height, mining and transportation methods and regulatory issues.

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

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

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

Other and Corporate includes marketing and administrative expenses, Matrix Design Group, LLC (“Matrix Design”), Alliance Design Group, LLC (“Alliance Design”) (collectively, Matrix Design and Alliance Design are referred to as the “Matrix Group”), the Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) dock activities, coal brokerage activity, our equity investment in Mid-America Carbonates, LLC (“MAC”) and certain properties of Alliance Resource Properties. Reportable segment results as of and for the three and six months ended June 30, 2011 and 2010 are presented below.

	Illinois Basin		Central Appalachia		Northern Appalachia		Other and Corporate		Elimination (1)			Consolidated
	(in thousands)
Reportable segment results for the three months ended June 30, 2011:
Total revenues (2)	$	323,214	$	57,521	$	69,493	$	10,967	$	(3,249	)	$	457,946
Segment Adjusted EBITDA Expense (3)		193,023		39,535		51,579		8,678		(3,249	)		289,566
Segment Adjusted EBITDA (4)		124,201		17,563		15,622		2,288		—			159,674
Capital expenditures		37,913		5,498		34,315		925		—			78,651

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Reportable segment results for the three months ended June 30, 2010:
Total revenues (2)	$	296,949	$	40,928	$	57,973	$	10,835	$	(6,342	)	$	400,343
Segment Adjusted EBITDA Expense (3)		174,590		31,921		41,616		9,157		(6,342	)		250,942
Segment Adjusted EBITDA (4)		115,872		8,911		14,121		1,676		—			140,580
Capital expenditures		51,191		3,161		42,684		355		—			97,391
Reportable segment results as of and for the six months ended June 30, 2011:
Total revenues (2)	$	640,801	$	105,226	$	123,196	$	20,644	$	(8,663	)	$	881,204
Segment Adjusted EBITDA Expense (3)		373,267		73,052		92,893		18,337		(8,663	)		548,886
Segment Adjusted EBITDA (4)		254,934		31,134		25,937		2,307		—			314,312
Total assets		798,452		91,271		367,514		369,763		(990	)		1,626,010
Capital expenditures		73,354		11,855		55,773		1,451		—			142,433
Reportable segment results as of and for the six months ended June 30, 2010:
Total revenues (2)	$	591,586	$	80,690	$	98,975	$	21,346	$	(11,593	)	$	781,004
Segment Adjusted EBITDA Expense (3)		347,443		64,746		73,587		18,018		(11,593	)		492,201
Segment Adjusted EBITDA (4)		230,001		15,834		21,111		3,331		—			270,277
Total assets		759,487		80,656		286,740		29,326		(2,707	)		1,153,502
Capital expenditures		83,389		4,520		85,991		948		—			174,848

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

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

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

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Segment Adjusted EBITDA Expense	$	289,566		$	250,942		$	548,886		$	492,201
Outside coal purchases		(5,842	)		(4,544	)		(9,631	)		(6,386	)
Other income		393			304			980			154
Operating expenses (excluding depreciation, depletion and amortization)	$	284,117		$	246,702		$	540,235		$	485,969

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Segment Adjusted EBITDA	$	159,674		$	140,580		$	314,312		$	270,277
General and administrative		(13,002	)		(11,628	)		(25,422	)		(22,329	)
Depreciation, depletion and amortization		(39,100	)		(35,677	)		(76,962	)		(71,973	)
Interest expense, net		(9,069	)		(7,391	)		(18,274	)		(14,935	)
Income tax expense		(325	)		(423	)		(96	)		(591	)
Net income	$	98,178		$	85,461		$	193,558		$	160,449

13. SUBSEQUENT EVENTS

On July 27, 2011, we declared a quarterly distribution for the quarter ended June 30, 2011, of $0.9225 per unit, on all common units outstanding, totaling approximately $55.3 million (which includes our managing general partner’s incentive distributions), payable on August 12, 2011 to all unitholders of record as of August 5, 2011.

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

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

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

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

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

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

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

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

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

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

Summary

We are a diversified producer and marketer of coal primarily to major United States (“U.S.”) utilities and industrial users. We began mining operations in 1971 and, since then, have grown through acquisitions and internal development to become the fourth largest coal producer in the eastern U.S. We operate nine underground mining complexes in Illinois, Indiana, Kentucky, Maryland and West Virginia. We are constructing a new mining complex in West Virginia, and we also operate a coal loading terminal on the Ohio River at Mt. Vernon, Indiana. In addition, on July 25, 2011, the board of directors of our managing general partner (“Board of Directors”) approved development of a new mine in Indiana. As is customary in the coal industry, we have entered into long-term coal supply agreements with many of our customers.

We have four reportable segments: Illinois Basin, Central Appalachia, Northern Appalachia and Other and Corporate. The first three reportable segments correspond to the three major coal producing regions in the eastern U.S. Factors similarly affecting financial performance of our operating segments within each of these three reportable segments include coal quality, coal seam height, mining and transportation methods and regulatory issues.

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

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

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

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

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

We reported record net income of $98.2 million for the three months ended June 30, 2011 (“2011 Quarter”) compared to $85.5 million for the three months ended June 30, 2010 (“2010 Quarter”). This increase of $12.7 million was principally due to improved pricing resulting in a record quarterly average coal sales price of $56.08 per ton sold for the 2011 Quarter, as compared to $51.53 per ton sold for the 2010 Quarter and record coal sales volumes, which increased to 7.9 million tons for the 2011 Quarter compared to 7.5 million tons for the 2010 Quarter. We had higher tons produced of 7.5 million tons in the 2011 Quarter compared to 6.9 million tons produced in the 2010 Quarter. The increase in produced tons primarily reflects increased production from our River View, Pattiki and Central Appalachia mines. Higher operating expenses during the 2011 Quarter resulted primarily from increased sales and production volumes, which particularly impacted materials and supplies expenses, sales-related expenses, maintenance costs and labor costs. Increased operating expenses also reflect increased incidental production at our Tunnel Ridge mine development project.

	Three Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)				(per ton sold)
Tons sold		7,890		7,489		N/A		N/A
Tons produced		7,535		6,917		N/A		N/A
Coal sales	$	442,483	$	385,905	$	56.08	$	51.53
Operating expenses and outside coal purchases	$	289,959	$	251,246	$	36.75	$	33.55

Coal sales. Coal sales for the 2011 Quarter increased 14.7% to $442.5 million from $385.9 million for the 2010 Quarter. The increase of $56.6 million in coal sales reflected the benefit of record coal sales prices (contributing $35.9 million in coal sales) and record tons sold (contributing $20.7 million in additional coal sales). Average coal sales prices in the 2011 Quarter increased $4.55 per ton sold to $56.08 per ton in the 2011 Quarter compared to $51.53 per ton in the 2010 Quarter, primarily as a result of improved contract pricing across all regions.

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Operating expenses. Operating expenses increased 15.2% to $284.1 million for the 2011 Quarter from $246.7 million for the 2010 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 by $11.6 million during the 2011 Quarter, which are generally included in variances discussed 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 6.9% to $11.92 per ton in the 2011 Quarter from $11.15 per ton in the 2010 Quarter. This increase of $0.77 per ton represents increased mine development labor and benefits at our Tunnel Ridge mine and the impact of decreased coal recoveries at our Dotiki, Warrior and Mettiki mines, partially offset by lower labor cost per ton resulting from increased production at our River View and Central Appalachian mines;

• Workers’ compensation expenses per ton produced increased to $1.09 per ton in the 2011 Quarter from $1.06 per ton in the 2010 Quarter. The increase of $0.03 per ton produced resulted primarily from favorable reserve adjustments during the 2010 Quarter;

• Material and supplies expenses per ton produced increased 16.7% to $12.14 per ton in the 2011 Quarter from $10.40 per ton in the 2010 Quarter. The increase of $1.74 per ton produced resulted from an increase in cost for certain products and services, primarily roof support (increase of $0.39 per ton), power and fuel used in the mining process (increase of $0.38 per ton), outside services and contract labor used in the mining process (increase of $0.40 per ton), ventilation (increase of $0.19 per ton) and rock dust (increase of $0.11 per ton) in addition to the negative cost impact of heightened regulatory oversight;

• Maintenance expenses per ton produced increased 13.0% to $4.08 per ton in the 2011 Quarter from $3.61 per ton in the 2010 Quarter. The increase of $0.47 per ton produced was primarily due to higher maintenance costs in various equipment categories in the Illinois Basin and Northern Appalachian regions, as well as increased longwall maintenance costs at our Mettiki mine;

• Mine administration expenses increased $3.6 million for the 2011 Quarter compared to the 2010 Quarter, primarily due to increased regulatory cost across all regions, increased costs associated with Matrix Design products and research, and higher insurance costs;

• Contract mining expenses increased $0.8 million for the 2011 Quarter compared to the 2010 Quarter due principally to increased production expenses at both third-party mining operations, which include transition costs associated with a new contract mining agreement and closure costs related to one of the third-party mining operations;

• Production taxes and royalties expenses (which were incurred as a percentage of coal sales prices and volumes) increased $0.27 per produced ton sold in the 2011 Quarter compared to the 2010 Quarter, primarily as a result of increased average coal sales prices across all regions; and

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

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General and administrative. General and administrative expenses for the 2011 Quarter increased to $13.0 million compared to $11.6 million in the 2010 Quarter. The increase of $1.4 million was primarily due to increases in salary expense and professional service fees.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, Matrix Design and other outside services and administrative services revenue from affiliates. Other sales and operating revenues increased to $6.8 million for the 2011 Quarter from $5.6 million for the 2010 Quarter. The increase of $1.2 million was primarily attributable to increased Matrix Design product sales.

Outside coal purchases. Outside coal purchases increased to $5.8 million for the 2011 Quarter from $4.5 million in the 2010 Quarter. The increase of $1.3 million was primarily attributable to increased coal brokerage activity as well as Mettiki’s higher cost per ton of coal purchased for sale into the export market.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $39.1 million for the 2011 Quarter from $35.7 million for the 2010 Quarter. The increase of $3.4 million was attributable to additional depreciation expense associated with capital expenditures related to the expansion of our River View mine, infrastructure and equipment expenditures at our Dotiki mine and capital expenditures related to various infrastructure improvements and efficiency projects at other mining operations.

Interest expense. Interest expense, net of capitalized interest, increased to $9.2 million for the 2011 Quarter from $7.4 million for the 2010 Quarter. The increase of $1.8 million was principally attributable to increased interest expense resulting from our $300 million term loan, which was completed in the fourth quarter of 2010, partially offset by reduced interest expense resulting from our August 2010 principal repayment of $18.0 million on our original senior notes issued in 1999, each of which is discussed in more detail below under “–Debt Obligations.”

Transportation revenues and expenses. Transportation revenues and expenses were $8.7 million and $8.8 million for the 2011 and 2010 Quarters, respectively. The decrease of $0.1 million was primarily attributable to reduced tonnage for which we arranged transportation at certain 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 $0.3 million for the 2011 Quarter compared to $0.4 million for the 2010 Quarter. Income taxes are primarily due to the operations of Matrix Design, which is owned by our subsidiary, Alliance Service, Inc. The decrease in income tax expense was due to lower annualized operating income from Matrix Design.

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Segment Adjusted EBITDA. Our 2011 Quarter Segment Adjusted EBITDA increased $19.1 million, or 13.6%, to a record $159.7 million from the 2010 Quarter Segment Adjusted EBITDA of $140.6 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are (in thousands):

	Three Months Ended June 30,
	2011			2010			Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	124,201		$	115,872		$	8,329		7.2	%
Central Appalachia		17,563			8,911			8,652		97.1	%
Northern Appalachia		15,622			14,121			1,501		10.6	%
Other and Corporate		2,288			1,676			612		36.5	%
Elimination		—			—			—		—
Total Segment Adjusted EBITDA (2)	$	159,674		$	140,580		$	19,094		13.6	%
Tons sold
Illinois Basin		6,328			6,113			215		3.5	%
Central Appalachia		708			543			165		30.4	%
Northern Appalachia		830			833			(3	)	(0.4	)%
Other and Corporate		24			—			24		(1	)
Elimination		—			—			—		—
Total tons sold		7,890			7,489			401		5.4	%
Coal sales
Illinois Basin	$	317,042		$	290,204		$	26,838		9.2	%
Central Appalachia		57,098			40,837			16,261		39.8	%
Northern Appalachia		66,360			54,859			11,501		21.0	%
Other and Corporate		1,983			5			1,978		(1	)
Elimination		—			—			—		—
Total coal sales	$	442,483		$	385,905		$	56,578		14.7	%
Other sales and operating revenues
Illinois Basin	$	181		$	257		$	(76	)	(29.6	)%
Central Appalachia		—			(5	)		5		(1	)
Northern Appalachia		842			878			(36	)	(4.1	)%
Other and Corporate		8,983			10,829			(1,846	)	(17.0	)%
Elimination		(3,249	)		(6,342	)		3,093		48.8	%
Total other sales and operating revenues	$	6,757		$	5,617		$	1,140		20.3	%
Segment Adjusted EBITDA Expense
Illinois Basin	$	193,023		$	174,590		$	18,433		10.6	%
Central Appalachia		39,535			31,921			7,614		23.9	%
Northern Appalachia		51,579			41,616			9,963		23.9	%
Other and Corporate		8,678			9,157			(479	)	(5.2	)%
Elimination		(3,249	)		(6,342	)		3,093		48.8	%
Total Segment Adjusted EBITDA Expense (3)	$	289,566		$	250,942		$	38,624		15.4	%

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

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

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

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

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

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

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

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

	Three Months Ended June 30,
	2011			2010
Segment Adjusted EBITDA	$	159,674		$	140,580
General and administrative		(13,002	)		(11,628	)
Depreciation, depletion and amortization		(39,100	)		(35,677	)
Interest expense, net		(9,069	)		(7,391	)
Income tax expense		(325	)		(423	)
Net income	$	98,178		$	85,461

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

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

	Three Months Ended
	June 30,
	2011			2010
Segment Adjusted EBITDA Expense	$	289,566		$	250,942
Outside coal purchases		(5,842	)		(4,544	)
Other income		393			304
Operating expense (excluding depreciation, depletion and amortization)	$	284,117		$	246,702

Illinois Basin – Segment Adjusted EBITDA increased 7.2% to $124.2 million in the 2011 Quarter from $115.9 million in the 2010 Quarter. The increase of $8.3 million was primarily attributable to improved contract pricing resulting in a higher average coal sales price of $50.10 per ton sold during the 2011 Quarter compared to $47.47 per ton sold for the 2010 Quarter. Coal sales increased 9.2% to $317.0 million in the 2011 Quarter compared to $290.2 million in the 2010 Quarter. The increase of $26.8 million primarily reflects the increase in the average coal sales price discussed above and increased tons produced and sold from our River View mine and Pattiki mine, which resumed full production in the first quarter of 2011, offset partially by weather disruptions and difficult mining conditions affecting certain other mining operations. Total Segment Adjusted EBITDA Expense for the 2011 Quarter increased 10.6% to $193.0 million from $174.6 million in the 2010 Quarter and increased $1.94 per ton sold to $30.50 from $28.56 per ton sold, primarily as a result of certain cost increases described above under consolidated operating expenses, as well as difficult mining conditions resulting in lower production at the Warrior and Dotiki mines and weather related disruptions at the Gibson North and Hopkins mines. These increases were partially offset by higher production at our River View and Pattiki mines and the impact on the 2010 Quarter of a $1.2 million loss on the retirement of certain assets related to the failed vertical hoist conveyor system at our Pattiki mine. For more information on Pattiki, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 4. Pattiki Vertical Hoist Conveyor System Failure In 2010” of this Quarterly Report on Form 10-Q.

Central Appalachia – Segment Adjusted EBITDA increased 97.1% to $17.6 million for the 2011 Quarter compared to $8.9 million in the 2010 Quarter. The increase of $8.7 million was primarily attributable to increased tons sold, which increased 30.4% to 0.7 million tons sold in the 2011 Quarter, as well as improved contract pricing resulting in a higher average coal sales price of $80.66 per ton sold during the 2011 Quarter compared to $75.24 per ton sold for the 2010 Quarter. Total Segment Adjusted EBITDA Expense for the 2011 Quarter increased 23.9% to $39.5 million from $31.9 million in the 2010 Quarter, primarily as a result of increased sales volumes and certain cost increases described above under consolidated operating expenses, as well as the impact of increasingly stringent regulatory compliance. Although Segment Adjusted EBITDA Expense increased, Segment Adjusted EBITDA expense per ton decreased 5.1% to $55.85 per ton in the 2011 Quarter from $58.82 per ton in the 2010 Quarter, primarily as a result of increased production at both Central Appalachian mines and particularly Pontiki, which added a fourth mining unit in the 2011 Quarter.

Northern Appalachia – Segment Adjusted EBITDA increased 10.6% to $15.6 million for the 2011 Quarter as compared to $14.1 million in the 2010 Quarter. This increase of $1.5 million was primarily attributable to improved contract pricing in the export coal markets resulting in a higher average sales price of $79.92 per ton sold for the 2011 Quarter compared to $65.87 per ton sold for the 2010 Quarter. Total Segment Adjusted EBITDA Expense for the 2011 Quarter increased 23.9% to $51.6

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million from $41.6 million in the 2010 Quarter and increased $12.15 per ton sold to $62.12 from $49.97 per ton sold, primarily as a result of increased cost per ton of coal purchased for sale into the export markets and lower coal recoveries due to difficult geologic conditions at the Mountain View mine, as well as the other cost increases described above under consolidated operating expenses, including expenses related to our Tunnel Ridge mine development project

Other and Corporate – Segment Adjusted EBITDA increased $0.6 million in the 2011 Quarter from the 2010 Quarter. This increase was primarily attributable to higher coal brokerage sales. Other sales and operating revenues decreased 17.0% to $9.0 million in the 2011 Quarter compared to $10.8 million for the 2010 Quarter. The decrease of $1.8 million was primarily attributable to decreased sales of mine safety equipment by the Matrix Group to our other mining subsidiaries (which are eliminated upon consolidation) and a decrease in Mt. Vernon outside transloading revenue resulting in part from weather disruptions. Segment Adjusted EBITDA Expense decreased 5.2% to $8.7 million for the 2011 Quarter compared to $9.2 million for the 2010 Quarter, primarily due to an increase in equity income from MAC, partially offset by increased component expenses and research costs associated with services revenue and safety equipment sales by the Matrix Group.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

We reported record net income of $193.6 million for the six months ended June 30, 2011 (“2011 Period”) compared to $160.4 million for the six months ended June 30, 2010 (“2010 Period”). This increase of $33.2 million was principally due to improved pricing resulting in an average coal sales price of $55.11 per ton sold for the 2011 Period, as compared to $50.44 per ton sold in the 2010 Period. We had tons sold of 15.4 million tons and tons produced of 15.8 million tons in the 2011 Period compared to 14.9 million tons sold and 14.5 million tons produced in the 2010 Period. This increase in produced tons primarily reflects increased production from our River View mine. Higher operating expenses during the 2011 Period resulted primarily from increased sales and production volumes, which particularly impacted materials and supplies expenses, sales-related expenses, maintenance costs and labor costs. Increased operating expenses also reflect increased incidental production at our Tunnel Ridge mine development project.

	Six Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)				(per ton sold)
Tons sold		15,428		14,870		N/A		N/A
Tons produced		15,755		14,461		N/A		N/A
Coal sales	$	850,168	$	750,064	$	55.11	$	50.44
Operating expenses and outside coal purchases	$	549,866	$	492,355	$	35.64	$	33.11

Coal sales. Coal sales for the 2011 Period increased 13.3% to $850.2 million from $750.1 million for the 2010 Period. The increase of $100.1 million in coal sales reflected the benefit of higher coal sales prices (contributing $72.1 million in coal sales) and increased tons sold (contributing $28.2 million in additional coal sales). Average coal sales prices increased $4.67 per ton sold to $55.11 per ton in the 2011 Period as compared to $50.44 per ton sold in the 2010 Period, primarily as a result of improved contract pricing across all regions.

Operating expenses. Operating expenses increased 11.2% to $540.2 million for the 2011 Period from $486.0 million for the 2010 Period primarily due to increased coal sales and production volumes. Increased River View production and Tunnel Ridge development combined to increase certain operating expenses by $29.5 million during the 2011 Period, which are generally included in variances discussed below. Operating expenses were impacted by various other factors, the most significant of which are discussed below:

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• Labor and benefit expenses per ton produced, excluding workers’ compensation, increased 6.3% to $11.31 per ton in the 2011 Period from $10.64 per ton in the 2010 Period. This increase of $0.67 per ton represents increased labor and benefits due to mine development at our Tunnel Ridge mine and decreased coal recoveries at our Dotiki, Warrior and Mettiki mines, partially offset by lower labor cost per ton resulting from increased production at our River View mine and Central Appalachian mines;

• Workers’ compensation expenses per ton produced increased to $1.05 per ton in the 2011 Period from $1.00 per ton in the 2010 Period. The increase of $0.5 per ton produced resulted primarily from favorable reserve adjustments during the 2010 Period;

• Material and supplies expenses per ton produced increased 17.9% to $11.74 per ton in the 2011 Period from $9.96 per ton in the 2010 Period. The increase of $1.78 per ton produced resulted from an increase in cost for certain products and services, primarily roof support (increase of $0.50 per ton), power and fuel used in the mining process (increase of $0.29 per ton), outside services and contract labor used in the mining process (increase of $0.44 per ton), ventilation (increase of $0.14 per ton), certain safety related materials and supplies (increase of $0.11 per ton) and rock dust (increase of $0.10 per ton) in addition to the negative cost impact of heightened regulatory oversight;

• Maintenance expenses per ton produced increased 17.1% to $4.05 per ton in the 2011 Period from $3.46 per ton in the 2010 Period. The increase of $0.59 per ton produced was primarily due to higher maintenance costs on continuous miners (increase of $0.13 per ton) in the Illinois Basin and Northern Appalachian regions, increased longwall maintenance costs at our Mettiki mine and higher costs in other various categories;

• Mine administration expenses increased $6.0 million for the 2011 Period compared to the 2010 Period, primarily due to increased regulatory costs, insurance costs and increased components expense associated with safety equipment sales by the Matrix Group. In addition, mine administration expenses increased during the 2011 Period due to costs incurred at Tunnel Ridge and Warrior related to reserve studies and mine planning activities;

• Contract mining expenses increased $1.9 million for the 2011 Period compared to the 2010 Period. The increase primarily reflects increased production and increased production expense from our existing contract mining operations in Northern Appalachia. Also contributing to increased contract mining expenses were transition costs associated with a new contract mining agreement and closure costs for one of the mining operations;

• Production taxes and royalties expenses (which were incurred as a percentage of coal sales prices and volumes) increased $0.38 per produced ton sold in the 2011 Period compared to the 2010 Period, primarily as a result of increased average coal sales prices across all regions;

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

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

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General and administrative. General and administrative expenses for the 2011 Period increased to $25.4 million compared to $22.3 million in the 2010 Period. The increase of $3.1 million was primarily due to increases in salary expense, incentive compensation expense and professional service fees.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, Matrix Design and other outside services and administrative services revenue from affiliates. Other sales and operating revenues increased to $13.0 million for the 2011 Period from $12.4 million for the 2010 Period. The increase of $0.6 million was primarily attributable to increased Matrix Design product sales and Mt. Vernon transloading revenues.

Outside coal purchases. Outside coal purchases increased to $9.6 million for the 2011 Period compared to $6.4 million in the 2010 Period. The increase of $3.2 million was primarily attributable to increased outside coal purchases related to our Northern Appalachian region due to increased demand in export coal markets, as well as increased coal brokerage activity.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $77.0 million for the 2011 Period from $72.0 million for the 2010 Period. The increase of $5.0 million was attributable to additional depreciation expense associated with capital expenditures related to the expansion of our River View mine, infrastructure and equipment expenditures at our Dotiki mine and capital expenditures related to various infrastructure improvements and efficiency projects at other mining operations.

Interest expense. Interest expense, net of capitalized interest, increased to $18.5 million for the 2011 Period from $15.0 million for the 2010 Period. The increase of $3.5 million was principally attributable to increased interest expense resulting from our $300 million term loan, which was completed in the fourth quarter of 2010, partially offset by reduced interest expense from our August 2010 principal repayment of $18.0 million on our original senior notes issued in 1999, each of which is discussed in more detail below under “–Debt Obligations.”

Transportation revenues and expenses. Transportation revenues and expenses were $18.0 million and $18.5 million for the 2011 and 2010 Periods, respectively. The decrease of $0.5 million was primarily attributable to reduced tonnage for which we arranged transportation at certain mines, partially offset by an increase in the average transportation rate in the 2011 Period reflecting higher spot contracts with pass-through 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 was $0.1 million for the 2011 Period compared to $0.6 million for the 2010 Period. Income taxes are primarily due to the operations of Matrix Design, which is owned by our subsidiary, Alliance Service, Inc. The decrease in income tax expense was due to lower annualized operating income in the 2011 Period from Matrix Design.

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Segment Adjusted EBITDA. Our 2011 Period Segment Adjusted EBITDA increased $44.0 million, or 16.3%, to $314.3 million from the 2010 Period Segment Adjusted EBITDA of $270.3 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are (in thousands):

	Six Months Ended June 30,
	2011			2010			Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	254,934		$	230,001		$	24,933		10.8	%
Central Appalachia		31,134			15,834			15,300		96.6	%
Northern Appalachia		25,937			21,111			4,826		22.9	%
Other and Corporate		2,307			3,331			(1,024	)	(30.7	)%
Elimination		—			—			—		—
Total Segment Adjusted EBITDA (2)	$	314,312		$	270,277		$	44,035		16.3	%
Tons sold
Illinois Basin		12,502			12,190			312		2.6	%
Central Appalachia		1,303			1,149			154		13.4	%
Northern Appalachia		1,599			1,531			68		4.4	%
Other and Corporate		24			—			24		(1	)
Elimination		—			—			—		—
Total tons sold		15,428			14,870			558		3.8	%
Coal sales
Illinois Basin	$	627,050		$	576,644		$	50,406		8.7	%
Central Appalachia		104,063			80,466			23,597		29.3	%
Northern Appalachia		117,072			92,940			24,132		26.0	%
Other and Corporate		1,983			14			1,969		(1	)
Elimination		—			—			—		—
Total coal sales	$	850,168		$	750,064		$	100,104		13.3	%
Other sales and operating revenues
Illinois Basin	$	1,150		$	800		$	350		43.8	%
Central Appalachia		123			114			9		7.9	%
Northern Appalachia		1,759			1,758			1		0.1	%
Other and Corporate		18,661			21,335			(2,674	)	(12.5	)%
Elimination		(8,663	)		(11,593	)		2,930		25.3	%
Total other sales and operating revenues	$	13,030		$	12,414		$	616		5.0	%
Segment Adjusted EBITDA Expense
Illinois Basin	$	373,267		$	347,443		$	25,824		7.4	%
Central Appalachia		73,052			64,746			8,306		12.8	%
Northern Appalachia		92,893			73,587			19,306		26.2	%
Other and Corporate		18,337			18,018			319		1.8	%
Elimination		(8,663	)		(11,593	)		2,930		25.3	%
Total Segment Adjusted EBITDA Expense (3)	$	548,886		$	492,201		$	56,685		11.5	%

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

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

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

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

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

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

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

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

	Six Months Ended
	June 30,
	2011			2010
Segment Adjusted EBITDA	$	314,312		$	270,277
General and administrative		(25,422	)		(22,329	)
Depreciation, depletion and amortization		(76,962	)		(71,973	)
Interest expense, net		(18,274	)		(14,935	)
Income tax expense		(96	)		(591	)
Net income	$	193,558		$	160,449

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

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

	Six Months Ended
	June 30,
	2011			2010
Segment Adjusted EBITDA Expense	$	548,886		$	492,201
Outside coal purchases		(9,631	)		(6,386	)
Other income		980			154
Operating expense (excluding depreciation, depletion and amortization)	$	540,235		$	485,969

Illinois Basin – Segment Adjusted EBITDA increased 10.8% to $254.9 million in the 2011 Period from $230.0 million in the 2010 Period. The increase of $24.9 million was primarily attributable to improved contract pricing resulting in a higher average coal sales price of $50.16 per ton sold during the 2011 Period compared to $47.31 per ton sold for the 2010 Period. Coal sales increased 8.7% to $627.1 million in the 2011 Period compared to $576.6 million in the 2010 Period. The increase of $50.5 million primarily reflects the increase in average coal sales price discussed above and increased tons produced and sold from our River View mine and Pattiki mine, which resumed full production in the first quarter of 2011, offset partially by weather disruptions and difficult mining conditions affecting certain mine operations. Total Segment Adjusted EBITDA Expense for the 2011 Period increased 7.4% to $373.3 million from $347.4 million in the 2010 Period and increased $1.36 per ton sold to $29.86 from $28.50 per ton sold, primarily as a result of certain cost increases described above under consolidated operating expenses, as well as lower production at the Dotiki and Warrior mines and weather related disruptions at the Gibson North and Hopkins mines. These increases were partially offset by higher production at our River View and Pattiki mines in the 2011 Period and the impact on the 2010 Period of a $1.2 million loss on the retirement of certain assets related to the failed vertical hoist conveyor system at our Pattiki mine. For more information on Pattiki, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 4. Pattiki Vertical Hoist Conveyor System Failure In 2010” of this Quarterly Report on Form 10-Q.

Central Appalachia – Segment Adjusted EBITDA increased 96.6% to $31.1 million for the 2011 Period, compared to $15.8 million for the 2010 Period. The increase of $15.3 million was primarily attributable to improved contract pricing resulting in a higher average coal sales price of $79.89 per ton sold during the 2011 Period compared to $70.01 per ton sold for the 2010 Period, as well as a 13.4% increase in tons sold to 1.3 million tons in the 2011 Period compared to 1.1 million tons sold in the 2010 Period. Total Segment Adjusted EBITDA Expense for the 2010 Period increased 12.8% to $73.1 million from $64.7 million in the 2010 Period, primarily as a result of certain cost increases described above under consolidated operating expenses as well as the impact of increasingly stringent regulatory compliance. Although Segment Adjusted EBITDA Expense increased, Segment Adjusted EBITDA expense per ton decreased 0.4% to $56.08 per ton in the 2011 Period from $56.33 per ton in the 2010 Period primarily as a result of increased production at both Central Appalachian mines and particularly Pontiki, which added a fourth mining unit during the 2011 Period.

Northern Appalachia – Segment Adjusted EBITDA increased 22.9% to $25.9 million for the 2011 Period, compared to $21.1 million for the 2010 Period. The increase of $4.8 million was primarily attributable to improved contract pricing in the export coal markets resulting in a higher average sales price of $73.20 per ton sold for the 2011 Period compared to $60.73 per ton sold for the 2010 Period. Improved demand in the export coal markets also resulted in higher tons sold, which increased 4.4% to

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1.6 million tons in the 2011 Period from 1.5 million tons in the 2010 Period. Total Segment Adjusted EBITDA Expense for the 2011 Period increased 26.2% to $92.9 million from $73.6 million in the 2010 Period and increased $10.00 per ton sold to $58.08 from $48.08 per ton sold, primarily as a result of higher coal sales volumes, increased costs associated with coal purchased for sale into the export market and lower coal recoveries due to adverse geologic conditions, as well as the other cost increases described above under consolidated operating expenses, including expenses related to our Tunnel Ridge mine development project.

Other and Corporate – Segment Adjusted EBITDA and other sales and operating revenues decreased $1.0 million and $2.7 million, respectively, in the 2011 Period compared to the 2010 Period. These decreases were primarily attributable to lower Matrix Group safety equipment sales and a decrease in Mt. Vernon outside transloading revenues. Segment Adjusted EBITDA Expense increased 1.8% to $18.3 million for the 2011 Period compared to $18.0 million for the 2010 Period, primarily due to increased component expenses and research costs associated with services revenue and safety equipment sales by the Matrix Group, partially offset by an increase in equity income from MAC during the 2011 Period and a loss associated with United Kingdom currency held during the 2010 Period.

Liquidity and Capital Resources

Liquidity

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

Cash Flows

Cash provided by operating activities was $261.4 million for the 2011 Period compared to $258.9 million for the 2010 Period. The increase in cash provided by operating activities was principally attributable to higher net income and an increase in the change in accounts payable in the 2011 Period compared to the 2010 Period. These increases in cash provided by operating activities were partially offset by a significant increase in coal inventory during the 2011 Period as compared to a decrease during the 2010 Period.

Net cash used in investing activities was $147.0 million for the 2011 Period compared to $183.6 million for the 2010 Period. The decrease in cash used for investing activities was primarily attributable to decreases in capital expenditures at Tunnel Ridge as a result of our construction timetable and River View due to the addition of mining units during the 2010 Period, partially offset by mine infrastructure and equipment expenditures at the Dotiki mine as well as increased capital expenditures at other mines and timing differences in accounts payable and accrued liabilities compared to the 2010 Period.

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Net cash used in financing activities was $106.8 million for the 2011 Period compared to $86.8 million for the 2010 Period. The increase in cash used in financing activities was primarily attributable to increased distributions paid to partners in the 2011 Period and net borrowings of $5.0 million under the ARLP Credit Facility in the 2010 Period.

Capital Expenditures

Capital expenditures decreased to $142.4 million in the 2011 Period from $174.8 million in the 2010 Period. See “—Cash Flows” above for additional information regarding capital expenditures.

Our anticipated total capital expenditures for the year ending December 31, 2011 are estimated in a range of $320.0 to $360.0 million. Management anticipates funding remaining 2011 capital requirements with cash and cash equivalents ($347.1 million as of June 30, 2011), cash flows provided by operations and borrowing available under the ARLP Credit Facility as discussed below. We will continue to have significant capital requirements over the long-term, which may require us to incur debt or seek additional equity capital. The availability and cost of additional capital will depend upon prevailing market conditions, the market price of our common units and several other factors over which we have limited control, as well as our financial condition and results of operations.

Debt Obligations

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

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

Senior Notes. Our Intermediate Partnership has $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 (together with the Series A senior notes, the “2008 Senior Notes”), which bear interest at 6.72% and mature on June 26, 2018 with interest payable semi-annually.

Term Loan. On December 29, 2010, our Intermediate Partnership entered into a term loan agreement (the “Term Loan Agreement”) with various financial institutions for a term loan (the “Term Loan”) in the aggregate principal amount of $300 million. The Term Loan bears interest at a variable rate plus an applicable margin which fluctuates depending upon whether we elect the Term Loan (or a portion thereof) to bear interest at the Base Rate or the Eurodollar Rate (as defined in the Term Loan Agreement).

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We have elected the Eurodollar Rate which, with applicable margin, was 2.3% as of June 30, 2011. Interest is payable quarterly with principal due as follows: $15 million due per quarter beginning March 31, 2013 through December 31, 2013, $18.75 million due per quarter beginning March 31, 2014 through September 30, 2015 and the balance of $108.75 million due on December 31, 2015. We have the option to prepay the Term Loan at any time in whole or in part subject to terms and conditions described in the Term Loan Agreement. Upon a “change of control” (as defined in the Term Loan Agreement), the unpaid principal amount of the Term Loan, all interest thereon and all other amounts payable under the Term Loan Agreement will become due and payable.

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

The ARLP Credit Facility, Senior Notes, 2008 Senior Notes and the Term Loan (collectively, “ARLP Debt Arrangements”) are guaranteed by all of the direct and indirect subsidiaries of our Intermediate Partnership. The ARLP Debt Arrangements contain various covenants affecting our Intermediate Partnership and its subsidiaries restricting, among other things, the amount of distributions by our Intermediate Partnership, the incurrence of additional indebtedness and liens, the sale of assets, the making of investments, the entry into mergers and consolidations and the entry into transactions with affiliates, in each case subject to various exceptions. The ARLP Debt Arrangements also require the Intermediate Partnership to remain in control of a certain amount of mineable coal reserves relative to its annual production. In addition, the ARLP Debt Arrangements require our Intermediate Partnership to maintain the following: (a) debt to cash flow ratio of not more than 3.0 to 1.0 and (b) cash flow to interest expense ratio of not less than 4.0 to 1.0, in both cases, during the four most recently ended fiscal quarters. The ARLP Credit Facility, Senior Notes and the 2008 Senior Notes limit our Intermediate Partnership’s maximum annual capital expenditures, excluding acquisitions, as described above. The debt to cash flow ratio and cash flow to interest expense ratio were 1.33 to 1.0 and 16.2 to 1.0, respectively, for the trailing twelve months ended June 30, 2011. Actual capital expenditures were $142.4 million for the 2011 Period. We were in compliance with the covenants of the ARLP Debt Arrangements as of June 30, 2011.

Other. In addition to the letters of credit available under the ARLP Credit Facility discussed above, we also have agreements with two banks to provide additional letters of credit in an aggregate amount of $31.1 million to maintain surety bonds to secure certain asset retirement obligations and our obligations for workers’ compensation benefits. At June 30, 2011, we had $30.7 million in letters of credit outstanding under agreements with these two banks. SGP previously guaranteed $5.0 million of these outstanding letters of credit. On May 4, 2011, the ARLP Partnership entered into the Amendment and Restatement of Letter of Credit Facility Agreement, dated as of October 2, 2010, which released SGP from its guarantee of these outstanding letters of credit.

Related-Party Transactions

We have continuing related-party transactions with our managing general partner, AHGP and SGP and its affiliates. These related-party transactions relate principally to the provision of administrative services to AHGP and Alliance Resource Holdings II, Inc. and their respective affiliates, a time sharing agreement concerning use of aircraft and mineral and equipment leases with SGP and its affiliates. We also had guarantees from SGP for certain letters of credit. However, these guarantees were released on May 4, 2011.

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

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New Accounting Standards

New Accounting Standards Issued and Adopted

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

New Accounting Standards Issued and Not Yet Adopted

In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 removes the presentation options in Accounting Standards Codification 220, Comprehensive Income, and requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. Under the two statement approach, the first statement would include components of net income, and the second statement would include components of other comprehensive income (“OCI”). ASU 2011-05 does not change the items that must be reported in OCI. ASU 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, and its provisions must be applied retrospectively for all periods presented in the financial statements. We do not anticipate the adoption of ASU 2011-05 on January 1, 2012 will have a material impact on our consolidated financial statements.

Other

Health Care Reform

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

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

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The Health Care Act amended previous legislation related to coal workers’ pneumoconiosis, or black lung, providing automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims. The impact of these changes to our current population of beneficiaries and claimants resulted in an estimated $8.3 million increase to our black lung obligation at December 31, 2010. This increase to our obligation excludes the impact of potential re-filing of closed claims and potential filing rates for employees who terminated more than seven years ago as we do not have sufficient information to determine what, if any, claims will be filed until regulations are issued. We expect these regulations to be issued during fiscal 2011.

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

The Dodd–Frank Act

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

Pattiki Vertical Hoist Conveyor System Failure In 2010

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

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

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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

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

Credit Risk

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

Exchange Rate Risk

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

Interest Rate Risk

Borrowings under the ARLP Credit Facility and Term Loan Agreement are at variable rates and, as a result, we have interest rate exposure. Historically, our earnings have not been materially affected by changes in interest rates. We do not utilize any interest rate derivative instruments related to our outstanding debt. We had no borrowings under the ARLP Credit Facility and $300.0 million outstanding under the Term Loan Agreement at June 30, 2011. A one percentage point increase in the interest rates related to the Term Loan Agreement would result in an annualized increase in 2011 interest expense of $3.0 million, based on borrowing levels at June 30, 2011. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a decrease of approximately $18.2 million in the estimated fair value of these borrowings.

As of June 30, 2011, the estimated fair value of the ARLP Debt Arrangements was approximately $767.9 million. The fair values of long-term debt are estimated using discounted cash flow analyses, based upon our current incremental borrowing rates for similar types of borrowing arrangements as of June 30, 2011. There were no other changes in our quantitative and qualitative disclosures about market risk as set forth in our Annual Report on Form 10-K for the year ended December 31, 2010.

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ITEM 4. CONTROLS AND PROCEDURES

We maintain controls and procedures designed to ensure that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act) was performed as of June 30, 2011. This evaluation was performed by our management, with the participation of our Chief Executive Officer and Chief Financial Officer. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective to ensure that the ARLP Partnership is able to collect, process and disclose the information it is required to disclose in the reports it files with the SEC within the required time periods, and during the quarterly period ended June 30, 2011, there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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FORWARD-LOOKING STATEMENTS

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

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

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

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

• the impact of recent health care legislation;

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

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

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

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

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

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

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

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

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

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

• unexpected changes in raw material costs;

• unexpected changes in availability of skilled labor;

• our ability to maintain satisfactory relations with our employees;

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

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

• greater than expected environmental regulation, costs and liabilities;

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

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

• results of litigation, including claims not yet asserted;

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

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

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

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• uncertainties in estimating and replacing our coal reserves;

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

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

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

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

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

• this Quarterly Report on Form 10-Q;

• other reports filed by us with the SEC;

• our press releases;

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

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

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PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in Part I, Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010 which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K and this Quarterly Report on Form 10-Q are not our only risks. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial based on current knowledge and factual circumstances, if such knowledge or facts change, also may materially adversely affect our business, financial condition and/or operating results in the future.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. RESERVED

ITEM 5. OTHER INFORMATION

Federal Mine Safety and Health Act Information

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

We are also a leader in developing and implementing new technologies to improve safety throughout the industry. For example, our subsidiary Matrix Design 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 twenty-six of its proximity detection systems functioning on continuous miners in our operating subsidiaries’ underground coal mines.

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Our industry is focused on improving employee safety and its safety performance is continuously monitored, including through the mining industry standard of “non-fatal days lost”, or “NFDL”, which reflects both the frequency and severity of injuries incurred and, we believe, is a better measure of safety performance than compliance statistics. As indicated in the chart below, these efforts have resulted in significant safety improvements as the industry average NFDL as of the first quarter of 2011, as reported^(a) by the Mine Safety and Health Administration (“MSHA”), has decreased approximately 65% since 1998.

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

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

Our mining operations are subject to extensive and stringent compliance standards established pursuant to the Federal Mine Safety and Health Act of 1977, as amended by the MINER Act (as amended, the “Mine Act”). MSHA monitors and rigorously enforces compliance with these standards, and our mining operations are inspected frequently. During the three months ended June 30, 2011, our mines were subject to 1,541 MSHA inspection days with an average of only 0.21 “significant and substantial”, or “S&S”, citations written per inspection day.

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

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

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

The Dodd—Frank Act requires issuers to include in periodic reports filed with the SEC certain information relating to citations or orders for violations of standards under the Mine Act. Responding to that legislation, we report that, for the three months ended June 30, 2011, none of our operating subsidiaries (a) received any violations under section 110(b)(2) of the Mine Act for failure to make reasonable efforts to eliminate a known violation of a mandatory safety or health standard that substantially proximately caused, or reasonably could have been expected to cause, death or serious bodily injury, (b) received any MSHA written notice under Mine Act section 104(e) of a pattern of violations of mandatory health or safety standards or the potential to have such a pattern, or (c) had any fatalities. For the three months ended June 30, 2011, our subsidiary, Webster County Coal, LLC, initiated one (1) legal proceeding before the Federal Mine Safety and Health Review Commission (“Commission”). The proceeding, which seeks an appeal of an administrative law judge’s decision in three consolidated cases involving Webster County Coal, LLC, is still pending. We have contests of 296 citations or orders pending before the administrative law judges of the Commission that were initiated during the three months ended June 30, 2011 and that involve all types of citations (i.e., not only S&S citations).

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

Subsidiary Name (1)	Section 104(a) Citations(2)		Section 104(b) Orders (3)		Section 104(d) Citations and Orders (4)		Section 107(a) Orders (5)		Total  Proposed Assessments (in thousands)  (6)
Illinois Basin Operations
Webster County Coal, LLC (KY)		61		—		—		—	$	43.1
Warrior Coal, LLC (KY)		35		1		2		1	$	7.7
Hopkins County Coal, LLC (KY)		16		—		—		—	$	3.5
River View Coal, LLC (KY)		19		—		—		—	$	3.3
White County Coal, LLC (IL)		36		—		3		—	$	16.1
Gibson County Coal, LLC (IN)		32		—		—		1	$	93.7
Central Appalachian Operations
Pontiki Coal, LLC (KY)		50		—		—		—	$	106.6
MC Mining, LLC (KY)		30		—		—		—	$	24.3
Northern Appalachian Operations
Mettiki Coal, LLC (MD)		3		—		—		—	$	0.1
Mettiki Coal (WV), LLC		21		—		—		—	$	2.6
Tunnel Ridge, LLC (PA/WV)		11		—		—		—	$	4.7

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

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

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

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

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

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

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ITEM 6. EXHIBITS

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File No. and Film No.	Exhibit	Filing Date	Filed Herewith*
31.1	Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated August 8, 2011, 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 August 8, 2011, 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 August 8, 2011, 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 August 8, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.					þ
101	Interactive Data File (Form 10-Q for the quarter ended June 30, 2011 furnished in XBRL). The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed” and, in accordance with Rule 406T of Regulation S-T, is not deemed “filed” or part of a registration statement or prospectus for purposes of Sections 11 and 12 of the Securities Act of 1933, as amended, and Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under these sections.

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, in Tulsa, Oklahoma, on August 8, 2011.

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

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