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, 2008

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 is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ¨  Yes    x  No

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

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

As of August 8, 2008, 36,613,458 Common Units are outstanding.

TABLE OF CONTENTS

	PART I
	FINANCIAL INFORMATION
		Page
ITEM 1.	Financial Statements (Unaudited)	1
	Alliance Resource Partners, L.P. and Subsidiaries
	Condensed Consolidated Balance Sheets as of June 30, 2008 and December 31, 2007	1
	Condensed Consolidated Statements of Income for the three and six months ended June 30, 2008 and 2007	2
	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2008 and 2007	3
	Notes to Condensed Consolidated Financial Statements	4
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	35
ITEM 4.	Controls and Procedures	36
	Forward-Looking Statements	37
	PART II
	OTHER INFORMATION
ITEM 1.	Legal Proceedings	39
ITEM 1A.	Risk Factors	39
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
ITEM 3.	Defaults upon Senior Securities	39
ITEM 4.	Submission of Matters to a Vote of Security Holders	39
ITEM 5.	Other Information	39
ITEM 6.	Exhibits	39

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PART 1

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, 2008			December 31, 2007
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	361,374		$	1,118
Trade receivables		81,028			92,667
Other receivables		5,180			3,399
Due from affiliates		207			139
Inventories		28,483			26,100
Advance royalties		4,452			4,452
Prepaid expenses and other assets		3,739			9,099
Total current assets		484,463			136,974
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost		1,004,012			948,210
Less accumulated depreciation, depletion and amortization		(453,337	)		(427,572	)
Total property, plant and equipment, net		550,675			520,638
OTHER ASSETS:
Advance royalties		21,700			25,974
Other long-term assets		16,644			18,137
Total other assets		38,344			44,111
TOTAL ASSETS	$	1,073,482		$	701,723
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	54,179		$	46,392
Due to affiliates		—			1,343
Accrued taxes other than income taxes		12,376			11,091
Accrued payroll and related expenses		17,376			15,180
Accrued interest		4,017			3,826
Workers’ compensation and pneumoconiosis benefits		8,038			8,124
Current capital lease obligation		365			377
Other current liabilities		9,110			6,754
Current maturities, long-term debt		18,000			18,000
Total current liabilities		123,461			111,087
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities		479,500			136,000
Pneumoconiosis benefits		30,403			29,392
Workers’ compensation		46,860			44,150
Asset retirement obligations		55,124			54,903
Due to affiliates		2,237			1,295
Long-term capital lease obligation		962			1,135
Minority interest		750			507
Other liabilities		7,503			6,037
Total long-term liabilities		623,339			273,419
Total liabilities		746,800			384,506
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
Limited Partners—Common Unitholders 36,613,458 and 36,550,659 units outstanding, respectively		623,965			607,777
General Partners’ deficit		(297,392	)		(290,669	)
Accumulated other comprehensive income		109			109
Total Partners’ capital		326,682			317,217
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,073,482		$	701,723

See notes to condensed consolidated financial statements.

1

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except unit and per unit data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
SALES AND OPERATING REVENUES:
Coal sales	$	261,567		$	242,364		$	530,725		$	481,234
Transportation revenues		11,007			10,606			21,627			19,285
Other sales and operating revenues		3,650			10,339			7,460			19,861
Total revenues		276,224			263,309			559,812			520,380
EXPENSES:
Operating expenses (excluding depreciation, depletion and amortization)		191,363			177,968			383,981			344,957
Transportation expenses		11,007			10,606			21,627			19,285
Outside purchases		4,552			7,607			7,455			13,873
General and administrative		12,119			8,266			20,950			16,195
Depreciation, depletion and amortization		25,600			21,425			48,894			41,218
Gain on sale of coal reserves		(5,159	)		—			(5,159	)		—
Net gain from insurance settlement and other		(2,790	)		(11,491	)		(2,790	)		(11,491	)
Total operating expenses		236,692			214,381			474,958			424,037
INCOME FROM OPERATIONS		39,532			48,928			84,854			96,343
Interest expense (net of interest capitalized for the three and six months ended June 30, 2008 and 2007 of $80, $347, $302 and $663, respectively)		(3,250	)		(2,842	)		(6,238	)		(5,660	)
Interest income		197			569			295			1,103
Other income		250			167			467			1,068
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST		36,729			46,822			79,378			92,854
INCOME TAX EXPENSE (BENEFIT)		(70	)		670			(725	)		1,244
INCOME BEFORE MINORITY INTEREST		36,799			46,152			80,103			91,610
MINORITY INTEREST (EXPENSE)		(102	)		85			(243	)		167
NET INCOME	$	36,697		$	46,237		$	79,860		$	91,777
GENERAL PARTNERS’ INTEREST IN NET INCOME	$	11,663		$	8,326		$	20,819		$	15,937
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	25,034		$	37,911		$	59,041		$	75,840
BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.67		$	0.80		$	1.43		$	1.60
DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.67		$	0.80		$	1.43		$	1.59
DISTRIBUTIONS PAID PER COMMON UNIT	$	0.585		$	0.54		$	1.17		$	1.08
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-BASIC		36,613,458			36,550,659			36,595,860			36,545,600
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-DILUTED		36,747,965			36,794,912			36,749,078			36,782,509

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,
	2008			2007
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	150,799		$	141,372
CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(70,950	)		(69,170	)
Changes in accounts payable and accrued liabilities		3,356			(7,315	)
Proceeds from sale of property, plant and equipment		567			3,048
Proceeds from sale of coal reserves		7,159			—
Proceeds from insurance settlement for replacement assets		—			2,511
Proceeds from marketable securities		—			260
Payment for acquisition of coal reserves and other assets		(13,300	)		(53,309	)
Advances on Gibson rail project		—			(5,888	)
Receipts of prior advances on Gibson rail project		1,023			—
Net cash used in investing activities		(72,145	)		(129,863	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		350,000			—
Borrowings under revolving credit facilities		88,850			23,585
Payments under revolving credit facilities		(95,350	)		—
Payments on capital lease obligation		(185	)		(151	)
Payment of debt issuance costs		(830	)		—
Cash contribution by General Partners		50			91
Distributions paid to Partners		(60,933	)		(54,171	)
Net cash provided by (used in) financing activities		281,602			(30,646	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		360,256			(19,137	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		1,118			36,789
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	361,374		$	17,652
SUPPLEMENTAL CASH FLOW INFORMATION:
CASH PAID FOR:
Interest	$	6,199		$	6,074
Income taxes	$	—		$	2,175
NON-CASH INVESTING ACTIVITY:
Purchase of property, plant and equipment	$	8,402		$	4,824

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 partner. SGP, a Delaware limited liability company, holds a 0.01% general partner interest in each of ARLP and the Intermediate Partnership. 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.

The accompanying condensed consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of June 30, 2008 and December 31, 2007, results of our operations for the three and six months ended June 30, 2008 and 2007 and our cash flows for the six months ended June 30, 2008 and 2007. All material intercompany transactions and accounts of the ARLP Partnership have been eliminated.

4

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, 2007.

2. 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.

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

3. ACQUISITIONS

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

5

In June 2007, our subsidiary, Alliance Resource Properties, acquired the rights to approximately 78.4 million tons of high-sulfur coal reserves in Webster and Hopkins County, Kentucky from Island Creek Coal Company, a subsidiary of Consol Energy, Inc. The purchase price of $53.3 million cash paid at closing was primarily allocated to owned and leased coal rights. We financed the purchase using a combination of existing cash on hand and borrowings under our revolving credit facility. We are mining these reserves from our adjacent Dotiki and Warrior mining complexes. As a result of the purchase, we reclassified 8.4 million tons of high-sulfur, non-reserve coal deposits as reserves. This acquisition represented an approximate 14% increase in our reserves at the acquisition date.

4. MC MINING MINE FIRE

On June 18, 2007, we agreed to a full and final resolution of our insurance claims relating to a mine fire that occurred on or about December 25, 2004 at our MC Mining, LLC’s (“MC Mining”) Excel No. 3 mine. This resolution included settlement of all expenses, losses and claims we incurred for the aggregate amount of $31.6 million, inclusive of $8.2 million of various deductibles and co-insurance, netting to $23.4 million of insurance proceeds paid to us. In 2006 and 2005, we received partial advance payments on the claims totaling $16.2 million, part of which we recognized as an offset to operating expenses ($0.4 million and $10.7 million in the three months ended March 31, 2006 and the year ended December 31, 2005, respectively), with the remaining $5.1 million of partial payments previously included in other current liabilities pending final claim resolution. In June 2007, as a result of this final resolution, we received additional cash payments of $7.2 million and recognized a net gain from insurance settlement of approximately $11.5 million, as well as a reduction in operating expenses of approximately $0.8 million. In May 2008, we realized a $2.8 million gain on settlement of our claim against the third-party that provided security services at the time of the fire.

5. LONG-TERM DEBT

Long-term debt consists of the following at June 30, 2008 and December 31, 2007 (in thousands):

	June 30, 2008			December 31, 2007
Credit facility	$	21,500		$	28,000
Senior notes		126,000			126,000
Series A senior notes		205,000			—
Series B senior notes		145,000			—
		497,500			154,000
Less current maturities		(18,000	)		(18,000	)
Total long-term debt	$	479,500		$	136,000

Credit Facility. On September 25, 2007, our Intermediate Partnership entered into a $150.0 million revolving credit facility (“ARLP Credit Facility”), which matures in 2012. Borrowings under the ARLP Credit Facility bear interest based on a floating base rate plus an applicable margin. The applicable margin is based on a leverage ratio of our Intermediate Partnership, as computed from time to time. For London Interbank Offered Rate (“LIBOR”) borrowings, the applicable margin under the ARLP Credit Facility ranges from 0.625% to 1.150% over LIBOR. As of June 30, 2008, the applicable margin for borrowings under the ARLP Credit Facility was 0.75% over LIBOR and the interest rate on the ARLP Credit Facility was 3.23%. Letters of credit up to $100.0 million can be issued under the ARLP Credit Facility. Outstanding letters of credit reduce amounts available under the ARLP Credit Facility. At June 30, 2008, we had $21.5 million of borrowings and $27.6 million of letters of credit outstanding, with $100.9 million available for borrowing under the ARLP Credit Facility. We incur an annual commitment fee of 0.175% on the undrawn portion of the ARLP Credit Facility.

6

Senior Notes. Our Intermediate Partnership has $126.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in seven remaining equal annual installments of $18.0 million with interest payable semi-annually (“Senior Notes”).

Series A Senior Notes. On June 26, 2008, our Intermediate Partnership entered into a Note Purchase Agreement (the “2008 Note Purchase Agreement”) with a group of institutional investors in a private placement offering. We issued $205.0 million of Series A Senior Notes, which bear interest at 6.28% and mature on June 26, 2015, with interest payable semi-annually.

Series B Senior Notes. On June 26, 2008, we issued under the 2008 Note Purchase Agreement $145.0 million of Series B Senior Notes, which bear interest at 6.72% and mature on June 26, 2018 with interest payable semi-annually.

The proceeds from the Series A and Series B Senior Notes (collectively, the “2008 Senior Notes”) will be used to repay the current amounts outstanding under the ARLP Credit Facility, to pay expenditures associated with the development of the River View Coal, LLC, (“River View”) mining complex, to pay expenses associated with the offering of the 2008 Senior Notes and for other general working capital requirements. We incurred debt issuance costs of approximately $1.5 million associated with the 2008 Senior Notes, which have been deferred and will be amortized as a component of interest expense over the term of the respective notes.

The ARLP Credit Facility, Senior Notes and 2008 Senior Notes (collectively “ARLP Debt Arrangements”) are guaranteed by all of the 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 comply with certain financial ratios, including a maximum leverage ratio and a minimum interest coverage ratio.

We were in compliance with the covenants of the ARLP Debt Arrangements as of June 30, 2008.

Other. We maintain agreements with two banks to provide additional letters of credit in an aggregate amount of $31.0 million to maintain surety bonds to secure certain asset retirement obligations and our obligations for workers’ compensation benefits. At June 30, 2008, we had $30.6 million in letters of credit outstanding under these agreements. Our special general partner guarantees $5.0 million of these outstanding letters of credit.

6. FAIR VALUE MEASUREMENTS

Effective January 1, 2008, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements, which, among other things, defines fair value, requires enhanced disclosures about assets and liabilities carried at fair value and establishes a hierarchal disclosure framework based upon the quality of inputs used to measure fair value. We have elected to defer the application of SFAS No. 157 to nonfinancial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis until our fiscal year beginning January 1, 2009, as permitted by Financial Accounting Standards Board (“FASB”) Staff Position No. Financial Accounting Standard 157-2. As a result of this deferral, we have not applied the provisions of SFAS No. 157 to asset retirement obligations initially measured at fair value.

7

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.

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

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

	Balance April 1, 2008		Accruals	Payments		Interest Accretion	Valuation Changes (Gain)/Loss		Balance June 30, 2008
Workers’ compensation liability	$	53,056	4,019	(3,105	)	765	(492	)	$	54,243
Long-term disability liability		2,776	175	(55	)	46	(372	)		2,570
	Balance December 31, 2007		Accruals	Payments		Interest Accretion	Valuation Changes (Gain)/Loss		Balance June 30, 2008
Workers’ compensation liability	$	51,619	8,200	(5,929	)	1,530	(1,177	)	$	54,243
Long-term disability liability		2,791	175	(116	)	92	(372	)		2,570

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

At June 30, 2008 and December 31, 2007, respectively, the estimated fair value of our fixed rate term debt was $483.3 million and $136.6 million, respectively, based on interest rates that we believe are currently available to us for issuance of debt with similar terms and remaining maturities. The increase in fair value of total debt during the six months ended to June 30, 2008 primarily reflects the issuance by our Intermediate Partnership of the 2008 Senior Notes aggregating $350 million in principal amount on June 26, 2008 (Note 5).

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, provides a fair value option election that allows companies to irrevocably elect fair value as the initial and subsequent measurement attribute for certain financial assets and liabilities not currently accounted for at fair value under other applicable accounting guidance. As of January 1, 2008, we have not elected to present any of our financial assets or liabilities currently recorded on our condensed consolidated balance sheet at fair value under SFAS No. 159.

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7. NET INCOME PER LIMITED PARTNER UNIT

In March 2004, the FASB issued Emerging Issues Task Force (“EITF”) No. 03-6, which addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitles the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. Essentially, EITF No. 03-6 provides that in any accounting period where our aggregate net income exceeds the aggregate distributions to unitholders for such period, we are required to present earnings per unit as if all of the earnings for the period were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during a particular period from an economic probability standpoint. EITF No. 03-6 does not impact our aggregate distributions to unitholders for any period, but it can have the impact of reducing our earnings per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the IDR held by our managing general partner, even though we make cash distributions on the basis of cash available for distributions to unitholders, not earnings, in any given accounting period. In accounting periods where aggregate net income does not exceed our aggregate distributions for such period, EITF No. 03-6 does not have any impact on our earnings per unit calculation. The following is a reconciliation of net income and weighted average units used in computing basic and diluted earnings per unit (in thousands, except per unit data):

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Net income	$	36,697		$	46,237		$	79,860		$	91,777
Adjustments:
General partner’s priority distributions		(11,152	)		(7,552	)		(19,614	)		(14,389	)
General partners’ 2% equity ownership		(511	)		(774	)		(1,205	)		(1,548	)
Limited partners’ interest in net income		25,034			37,911			59,041			75,840
Additional earnings allocation to general partners		(426	)		(8,543	)		(6,591	)		(17,453	)
Net income available to limited partners under EITF No. 03-6	$	24,608		$	29,368		$	52,450		$	58,387
Weighted average limited partner units – basic		36,613			36,551			36,596			36,546
Basic net income per limited partner unit	$	0.67		$	0.80		$	1.43		$	1.60
Weighted average limited partner units – basic		36,613			36,551			36,596			36,546
Units contingently issuable:
Restricted units for Long-Term Incentive Plan		135			133			134			117
Directors’ compensation units		—			32			6			33
Supplemental Executive Retirement Plan		—			79			13			87
Weighted average limited partner units, assuming dilutive effect of restricted units		36,748			36,795			36,749			36,783
Diluted net income per limited partner unit	$	0.67		$	0.80		$	1.43		$	1.59

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Our net income for partners’ capital purposes is allocated to the general partners and limited partners in accordance with their respective partnership percentages, after giving effect to any special income allocations, including incentive distributions to our managing general partner, the holder of the IDR pursuant to our partnership agreement, which are declared and paid following the close of each quarter. For purposes of computing basic and diluted net income per limited partner unit, in periods when our aggregate net income exceeds the aggregate distributions to unitholders for such periods, an increased amount of net income is allocated to the general partners for the additional pro forma priority income attributable to the application of EITF No. 03-6. On January 1, 2009 we will adopt the provisions of EITF 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships. We expect the adoption of EITF No. 07-4 will impact our presentation of earnings per unit (Note 10).

On January 29, 2008 the compensation committee of the board of directors of our managing general partner (“Compensation Committee”) approved amendments to the Deferred Compensation Plan for Directors and Supplemental Executive Retirement Plan to require that vested benefits be paid to participants in cash only, rather than a combination of cash and/or common units of ARLP. As a result, the dilutive effect of phantom units associated with these plans is no longer considered in the calculation of diluted units effective January 29, 2008.

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.

8. COMPENSATION PLANS

We have a Long-Term Incentive Plan (“LTIP”) for certain of our employees and directors of our managing general partner and its affiliates who perform services for us. The LTIP awards are of non-vested phantom units, which upon satisfaction of vesting requirements entitle the LTIP participant to receive ARLP common units. On January 29, 2008, the Compensation Committee determined that the vesting requirements for the 2005 grants of 92,730 restricted units (which is net of 21,660 forfeitures) had been satisfied as of January 1, 2008. As a result of this vesting, on February 21, 2008, we issued 62,799 unrestricted common units to LTIP participants. The remaining units were settled in cash to satisfy the tax withholding obligations for the LTIP participants. On January 29, 2008, the Compensation Committee authorized additional grants of up to 100,000 restricted units, of which 93,600 restricted units have been issued and will vest January 1, 2011, subject to the satisfaction of certain financial tests. The fair value of the 2008 grants, which is equal to the intrinsic value at the date of grant, was $36.11 per unit on a weighted average basis. After consideration of the above mentioned transactions, as of June 30, 2008, 124,161 units remain available for issuance in the future, assuming that all grants currently issued and outstanding for 2006, 2007 and 2008 are settled with common units and no future forfeitures occur. LTIP expense was $0.8 million, $0.8 million, $1.5 million and $1.4 million, for the three and six months ended June 30, 2008 and 2007, respectively.

As of June 30, 2008, there was $4.7 million in total unrecognized compensation expense related to the non-vested LTIP grants. That expense is expected to be recognized over a weighted-average period of 1.6 years. As of June 30, 2008, the intrinsic value of the non-vested LTIP grants was $14.2 million. As of June 30, 2008, the total obligation associated with the LTIP was $4.1 million and is included in the partners’ capital-limited partners line item in our condensed consolidated balance sheets.

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9. COMPONENTS OF PENSION PLAN NET PERIODIC BENEFIT COSTS

Employees at certain of our mining operations participate in a defined benefit plan (the “Pension Plan”) that we sponsor. In some instances new employees of these participating operations will not be eligible to participate in the Pension Plan, but will be eligible to participate in a defined contribution profit sharing and savings plan (“PSSP”) that we sponsor. Certain employees participating in the Pension Plan will have the option to remain in the Pension Plan or participate in enhanced benefit provisions under the PSSP. Components of the net periodic benefit cost for each of the periods presented are as follows (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Service cost	$	704		$	858		$	1,407		$	1,717
Interest cost		652			567			1,305			1,134
Expected return on plan assets		(879	)		(671	)		(1,759	)		(1,343	)
Amortization of actuarial loss		—			65			—			129
Net periodic benefit cost	$	477		$	819		$	953		$	1,637

We previously disclosed in our financial statements for the year ended December 31, 2007, that we expected to contribute $2.5 million to the Pension Plan in 2008. We typically make a single contribution to our Pension Plan in the third quarter of a year. Accordingly, as of June 30, 2008, we had made no contributions to the Pension Plan in 2008.

10. NEW ACCOUNTING STANDARDS

New Accounting Standards Issued and Adopted

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This standard defines fair value, establishes a framework for measuring fair value in accounting principles generally accepted in the United States of America, and expands disclosure about fair value measurements. SFAS No. 157 applies under other accounting standards that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurement. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 with the exception of nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value on a nonrecurring basis for which the requirements of SFAS No. 157 have been deferred by the FASB for one year. The adoption of SFAS No. 157 on January 1, 2008 did not have a material impact on our condensed consolidated financial statements (Note 6).

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 allows entities to choose to measure at fair value financial instruments and certain other eligible items which are not otherwise currently required to be measured at fair value. Under SFAS No. 159, the decision to measure items at fair value is made at specified election dates on an irrevocable instrument-by-instrument basis. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We have not elected to present any of our financial assets or liabilities currently recorded on our condensed consolidated balance sheet at fair value under SFAS No. 159; therefore, the adoption of SFAS No. 159 on January 1, 2008 did not have a material impact on our condensed consolidated financial statements (Note 6).

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New Accounting Standards Issued and Not Yet Adopted

In December 2007, the FASB issued SFAS No. 141R, Business Combinations, and SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements. SFAS Nos. 141R and 160 require most identifiable assets, liabilities, noncontrolling interests and goodwill acquired in a business combination to be recorded at “full fair value” and require noncontrolling interests (previously referred to as minority interests) to be reported as a component of equity, which changes the accounting for transactions with noncontrolling interest holders. Both statements are effective for periods beginning on or after December 15, 2008 and earlier adoption is prohibited. SFAS No. 141R will be applied to business combinations occurring after the effective date and SFAS No. 160 will be applied prospectively to all noncontrolling interests, including any that arose before the effective date. We are currently evaluating the requirements of SFAS Nos. 141R and 160 and have not yet determined the impact on our condensed consolidated financial statements.

In March 2008, the FASB issued EITF No. 07-4, which considers whether the IDR of a master limited partnership represents a participating security when considered in the calculation of earnings per unit under the two-class method. The EITF considers whether the partnership agreement contains any contractual limitations concerning distributions to IDR holders that would impact the amount of earnings to allocate to the IDR holders for each reporting period. If distributions are contractually limited to the IDR holders’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the IDR holders. In addition, the EITF presents alternative methods for inclusion of IDR in the earnings per unit computation. When cash distributions exceed net income for the period, net income should be reduced by the distributions made to the holders of the general partner interest, the holder of the limited partner interest and IDR holders for the period. The provisions of EITF No. 07-4 are effective for fiscal years beginning after December 15, 2008. We expect the adoption of EITF No. 07-4 will impact our presentation of earnings per unit. We currently present earnings per unit as though all earnings were distributed each quarter (Note 7). Under the new guidance of EITF No. 07-4, we believe our partnership agreement contractually limits our distributions to available cash and therefore undistributed earnings will no longer be allocated to the IDR holder upon adoption of EITF No. 07-4 effective January 1, 2009.

In June 2008, the FASB issued Staff Position (“FSP”) No. EITF No. 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities.” This FSP affects entities that accrue cash dividends on share-based payment awards during the awards’ service period when the dividends do not need to be returned if the employees forfeit the award. The FSP requires that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders and are considered participating securities. Because the awards are considered participating securities, the issuing entity is required to apply the two-class method of computing basic and diluted earnings per share. The provisions of FSP No. EITF No. 03-6-1 are effective for fiscal years beginning after December 15, 2008. We are currently evaluating the requirements of FSP No. EITF 03-6-1, to determine the impact, if any, on our consolidated financial statements.

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11. COMPREHENSIVE INCOME

The following table summarizes the effect of the amortization of actuarial loss related to our pension plan on other comprehensive income for the three and six months ended June 30, 2008 and 2007, respectively, (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
Net income	$	36,697	$	46,237	$	79,860	$	91,777
Amortization of actuarial loss		—		129		—		129
Comprehensive income	$	36,697	$	46,366	$	79,860	$	91,906

Comprehensive income differs from net income by the amount of amortization of actuarial loss associated with the adoption of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans —- an amendment of FASB Statements No. 87, 88, 106, and 132 (R).

12. SEGMENT INFORMATION

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

The Illinois Basin segment is comprised of Webster County Coal’s Dotiki mine, Gibson County Coal, LLC’s Gibson North mine and Gibson South property, Hopkins County Coal’s Elk Creek mine, White County Coal, LLC’s (“White County Coal”) Pattiki mine, Warrior Coal’s Cardinal mine, River View property and certain properties of Alliance Resource Properties (Note 3). In 2007, mine development began at our River View property. We are in the process of permitting the Gibson South property for future mine development.

The Central Appalachian segment is comprised of Pontiki Coal, LLC’s Pond Creek and Van Lear mines, and MC Mining’s Excel No. 3 mine.

The Northern Appalachian segment is comprised of Mettiki Coal, LLC, Mettiki Coal (WV) LLC’s Mountain View mine, two small mining operations where we sub-contract operations to third parties, and the Tunnel Ridge, LLC (“Tunnel Ridge”) and Penn Ridge Coal, LLC (“Penn Ridge”) coal properties. We are in the process of permitting the Tunnel Ridge and Penn Ridge properties for future mine development.

Other and Corporate includes marketing and administrative expenses, the Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) dock activities, coal brokerage activity, Mid-America Carbonates, LLC (“MAC”), Matrix Design Group, LLC (“Matrix Design”) and certain properties of Alliance Resource Properties. Operating segment results for the three and six months ended June 30, 2008 and 2007 are presented below:

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	Illinois Basin		Central Appalachia		Northern Appalachia		Other and Corporate		Elimination (1)			Consolidated
	(in thousands)
Operating segment results for the three months ended June 30, 2008:
Total revenues (2)	$	176,642	$	52,729	$	44,441	$	5,175	$	(2,763	)	$	276,224
Segment Adjusted EBITDA Expense (3)		121,495		38,599		33,656		4,575		(2,660	)		195,665
Segment Adjusted EBITDA (4)		47,306		16,927		7,613		5,757		(102	)		77,501
Capital expenditures		30,788		1,868		3,195		1,050		—			36,901
Operating segment results for the three months ended June 30, 2007:
Total revenues (2)	$	167,909	$	53,009	$	39,790	$	3,474	$	(873	)	$	263,309
Segment Adjusted EBITDA Expense (3)		114,392		37,396		31,289		3,204		(873	)		185,408
Segment Adjusted EBITDA (4)		46,372		26,489		5,655		270		—			78,786
Capital expenditures (5)		27,987		3,310		5,993		1,155		—			38,445
Operating segment results for the six months ended June 30, 2008:
Total revenues (2)	$	368,555	$	102,062	$	84,753	$	9,120	$	(4,678	)	$	559,812
Segment Adjusted EBITDA Expense (3)		248,521		76,748		61,849		8,547		(4,696	)		390,969
Segment Adjusted EBITDA (4)		104,756		28,049		16,611		5,731		18			155,165
Total assets		472,581		93,437		130,805		376,715		(56	)		1,073,482
Capital expenditures (6)		59,991		3,918		5,664		1,377		—			70,950
Operating segment results for the six months ended June 30, 2007:
Total revenues (2)	$	335,782	$	96,512	$	78,570	$	11,668	$	(2,152	)	$	520,380
Segment Adjusted EBITDA Expense (3)		220,778		70,117		57,957		11,062		(2,152	)		357,762
Segment Adjusted EBITDA (4)		102,868		36,836		14,515		605		—			154,824
Total assets		433,698		102,727		126,839		32,630		—			695,894
Capital expenditures (5)		50,570		6,459		10,318		1,823		—			69,170

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

(2) Revenues included in the Other and Corporate column are primarily attributable to Mt. Vernon transloading revenues, administrative service revenues from affiliates, Matrix Design revenues and MAC rock dust revenues for the three and six months ended June 30, 2008 and brokerage sales, Mt. Vernon transloading revenues, administrative service revenues from affiliates, and Matrix Design revenues for the three and six months ended June 30, 2007.

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

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Segment Adjusted EBITDA Expense	$	195,665		$	185,408		$	390,969		$	357,762
Outside purchases		(4,552	)		(7,607	)		(7,455	)		(13,873	)
Other income		250			167			467			1,068
Operating expenses (excluding depreciation, depletion and amortization)	$	191,363		$	177,968		$	383,981		$	344,957

(4) Segment Adjusted EBITDA is defined as income before income taxes, minority interest, interest income, interest expense, depreciation, depletion and amortization, and general and administrative expense. Segment Adjusted EBITDA is reconciled to net income below (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Segment Adjusted EBITDA	$	77,501		$	78,786		$	155,165		$	154,824
General and administrative		(12,119	)		(8,266	)		(20,950	)		(16,195	)
Depreciation, depletion and amortization		(25,600	)		(21,425	)		(48,894	)		(41,218	)
Interest expense, net		(3,053	)		(2,273	)		(5,943	)		(4,557	)
Income tax (expense) benefit		70			(670	)		725			(1,244	)
Minority interest (expense)		(102	)		85			(243	)		167
Net income	$	36,697		$	46,237		$	79,860		$	91,777

(5) Capital expenditures for the three and six months ended June 30, 2007 do not include acquisitions of coal reserves and other assets in the Illinois Basin of $53.3 million separately reported in our condensed consolidated statements of cash flows.

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

13. MINORITY INTEREST

In March 2006, White County Coal and Alexander J. House (“House”) entered into a limited liability company agreement to form MAC. MAC was formed to engage in the development and operation of a rock dust mill and to manufacture and sell rock dust. White County Coal initially invested $1.0 million in exchange for a 50% equity interest in MAC. We consolidate MAC’s financial results in accordance with FASB Interpretation (“FIN”) No. 46R, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. Based on the guidance in FIN No. 46R, we concluded that MAC is a variable interest entity and that we are the primary beneficiary. House’s equity ownership in the net assets of MAC was $0.8 million and $0.5 million at June 30, 2008 and December 31, 2007, respectively, which is recorded as minority interest on our condensed consolidated balance sheet.

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On March 19, 2007, MAC entered into a secured line of credit (“LOC”) with an outside third-party, which was scheduled to expire on March 19, 2008. In September 2007, MAC entered into a $1.5 million Revolving Credit Agreement (“Revolver”) with ARLP. Concurrent with the execution of the Revolver, MAC repaid all amounts outstanding under the LOC. By amendment effective April 1, 2008, the term of the Revolver was extended to June 30, 2009. Due to the consolidation of MAC in accordance with FIN No. 46R, the intercompany transactions associated with the Revolver are eliminated.

14. SUBSEQUENT EVENTS

On July 28, 2008, we declared a quarterly distribution for the quarter ended June 30, 2008, of $0.66 per unit, totaling approximately $35.8 million (which includes our managing general partner’s incentive distributions), on all common units outstanding, payable on August 14, 2008 to all unitholders of record as of August 7, 2008.

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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 to major United States utilities and industrial users. We began mining operations in 1971 and, since then, have grown through acquisitions and internal development to become what we believe to be the fourth largest coal producer in the eastern United States. We currently operate eight mining complexes in Illinois, Indiana, Kentucky, Maryland and West Virginia. We are constructing a ninth mining complex in Kentucky and also operate a coal loading terminal on the Ohio River at Mt. Vernon, Indiana. As is customary in the coal industry, we have entered into long-term coal supply agreements with many of our customers, and we have contractual commitments for substantially all of our remaining 2008 production.

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

• Illinois Basin segment is comprised of Webster County Coal, LLC’s (“Webster County Coal”) Dotiki mine, Gibson County Coal, LLC’s Gibson North mine and Gibson South property, Hopkins County Coal, LLC’s (“Hopkins County Coal”) Elk Creek mine, White County Coal, LLC’s (“White County Coal”) Pattiki mine and Warrior Coal, LLC’s (“Warrior Coal”) Cardinal mine, River View Coal, LLC’s (“River View”) property and certain properties of Alliance Resource Properties, LLC (“Alliance Resource Properties”). In 2007, mine development began at the River View property. We are in the process of permitting the Gibson South property for future mine development.

• Central Appalachian segment is comprised of Pontiki Coal, LLC’s (“Pontiki Coal”) Pond Creek and Van Lear mines, and MC Mining, LLC’s (“MC Mining”) Excel No. 3 mine.

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• Northern Appalachian segment is comprised of Mettiki Coal, LLC, Mettiki Coal (WV) LLC’s Mountain View mine, two small third-party mining operations, and the Tunnel Ridge, LLC (“Tunnel Ridge”) and Penn Ridge Coal, LLC (“Penn Ridge”) coal properties. We are in the process of permitting the Tunnel Ridge and Penn Ridge properties for future mine development.

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

Expiration of Federal Non-Conventional Source Fuel Tax Credit

Historically, we received material revenues from coal sales, rental, marketing and other services provided under synfuel-related agreements at three of our mining operations. As anticipated, operations at these third-party synfuel facilities ended in December 2007 as the federal non-conventional source fuel tax credits expired. As a result, we no longer sell coal to the synfuel operators, but sell that coal directly to our customers, including Louisville Gas and Electric Company, Seminole Electric Cooperative, Inc, Tennessee Valley Authority and Virginia Electric and Power Company, each of which individually accounted for 10% or more of our total revenues for the three months ended June 30, 2008 (“2008 Quarter”) and six months ended June 30, 2008 (“2008 Period”), among other customers.

Results of Operations

Comparison of our operating results for the 2008 Quarter and the three months ended June 30, 2007 (“2007 Quarter”) and the 2008 Period and the six months ended June 30, 2007 (“2007 Period”) is affected by the following significant items:

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

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

• Gain of $2.8 million on settlement of claims against the third-party that provided security services at the time of the December 2004 MC Mining mine fire (“MC Mining Fire Incident”) was recognized in the 2008 Quarter. Additionally, in the 2007 Quarter we recognized a net gain of $11.5 million from an insurance settlement of claims relating to the MC Mining Fire Incident as well as a reduction in operating expenses of approximately $0.8 million. Please read “–MC Mining Mine Fire” below; and

• The 2007 Quarter and the 2007 Period realized net income of approximately $8.8 million and $16.9 million, respectively, from various coal synfuel-related agreements. Our synfuel related arrangements are discussed in more detail above.

Three Months Ended June 30, 2008 Compared to Three Months Ended June 30, 2007

We reported net income of $36.7 million for the 2008 Quarter compared to $46.2 million for the 2007 Quarter. This decrease of $9.5 million was principally due to the significant items discussed above and higher depreciation, depletion and amortization resulting from capital expenditures associated with ARLP’s growth initiatives, partially offset by improved coal sales. We had tons sold of

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6.6 million and tons produced of 6.5 million for the 2008 Quarter compared to 6.3 million tons sold and 5.6 million tons produced for the 2007 Quarter. Increased operating expenses during the 2008 Quarter primarily reflect the increase in tons produced and higher sales related expenses resulting from increased coal sales, as well as higher regulatory compliance costs and other factors described below.

	Three Months Ended June 30,
	2008		2007		2008		2007
	(in thousands)				(per ton sold)
Tons sold		6,622		6,279		N/A		N/A
Tons produced		6,467		5,638		N/A		N/A
Coal sales	$	261,567	$	242,364	$	39.50	$	38.60
Operating expenses and outside purchases	$	195,915	$	185,575	$	29.59	$	29.55

Coal sales. Coal sales for the 2008 Quarter increased 7.9% to $261.6 million from $242.4 million for the 2007 Quarter. The increase of $19.2 million reflected tons sold of 6.6 million (contributing $13.2 million of the increase) for the 2008 Quarter compared to 6.3 million for the 2007 Quarter and higher average coal sales prices (contributing $6.0 million of the increase). Tons produced increased 14.7% to 6.5 million tons for the 2008 Quarter from 5.6 million tons for the 2007 Quarter.

Operating expenses. Operating expenses increased 7.5% to $191.4 million for the 2008 Quarter from $178.0 million for the 2007 Quarter. The increase of $13.4 million resulted from the impact of the following specific factors:

• Higher operating expenses associated with an additional 467,000 produced tons sold;

• Labor and benefit expenses per ton produced decreased to $10.11 per ton in the 2008 Quarter from $10.43 per ton in the 2007 Quarter reflecting decreased workers’ compensation costs partially offset by increased headcount due to capacity expansion, pay rate and benefit increases and increased health care costs;

• Material and supplies, and maintenance expenses per ton produced increased 1.9% and 1.6%, respectively, to $9.79 and $3.20 per ton, respectively, in the 2008 Quarter from $9.61 and $3.15 per ton, respectively, in the 2007 Quarter. The respective increases of $0.18 and $0.05 per ton produced resulted from increased costs for certain products and services (particularly roof support, seals, power and fuel) used in the mining process and higher regulatory compliance costs;

• Production taxes and royalties (which are incurred as a percentage of coal sales revenue or volumes) increased $0.8 million as a result of increased tons sold and increased average coal sales prices;

• Reduced expenses of $0.8 million in the 2008 Quarter as compared to the 2007 Quarter were associated with the purchase and sale of coal during the 2007 Quarter under a settlement agreement we entered into with ICG, LLC (“ICG”) in November 2005. For more information, please read our Annual Report on Form 10-K for the year ended December 31, 2007, “Other” under “Item 8. Financial Statements and Supplementary Data – Note 19. Commitments and Contingencies.” Consistent with the guidance in the Financial Accounting Standards Board’s (“FASB”) Emerging Issues Task Force (“EITF”) No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, Pontiki Coal’s sale of coal to ICG and Alliance Coal’s purchase of coal from ICG pursuant to that settlement agreement are combined. Therefore, the excess of Alliance Coal’s purchase price from ICG over Pontiki Coal’s sales price to ICG is reported as an operating expense. We fully satisfied our coal sales agreement with ICG in April 2007;

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

• The 2007 Quarter includes a $0.8 million reduction in operating expenses as a result of the final insurance settlement of the MC Mining Fire Incident. Please read “–MC Mining Mine Fire” below.

General and administrative. General and administrative expenses for the 2008 Quarter increased to $12.1 million compared to $8.3 million in the 2007 Quarter. The increase was primarily due to higher salary and benefit costs related to increased staffing levels and higher incentive and unit-based compensation expense.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, products and services provided by MAC and Matrix Design, and other outside services and administrative services revenue from affiliates. The 2007 Quarter also includes rental and service fees from third-party coal synfuel facilities. Other sales and operating revenues decreased to $3.7 million for the 2008 Quarter from $10.3 million for the 2007 Quarter. The decrease of $6.6 million was primarily attributable to the loss of synfuel-related benefits due to the expiration of the non-conventional synfuel tax credits on December 31, 2007, partially offset by increased revenues from transloading services and MAC product sales. Our synfuel-related arrangements are discussed in more detail above under “–Summary.”

Outside purchases. Outside purchases decreased to $4.6 million for the 2008 Quarter from $7.6 million in the 2007 Quarter. The decrease of $3.0 million was primarily attributable to a decrease in outside purchases at our Illinois Basin and Central Appalachian regions partially offset by increased outside purchases in the Northern Appalachian region to supply attractive opportunities in the spot and export markets.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $25.6 million for the 2008 Quarter from $21.4 million for the 2007 Quarter. The increase of $4.2 million was primarily attributable to additional depreciation expense associated with continuing capital expenditures related to infrastructure improvements, efficiency projects and expansion of production capacity.

Interest expense. Interest expense, net of capitalized interest increased to $3.2 million for the 2008 Quarter from $2.8 million for the 2007 Quarter. The increase of $0.4 million was principally attributable to increased interest expense due to increased borrowings under the revolving credit facility in addition to interest expense incurred on our recently completed $350 million private placement of senior notes, partially offset by reduced interest expense from our August 2007 principal payment of $18.0 million on our existing senior notes. Our recently completed $350 million private placement of senior notes is discussed in more detail below under “–Debt Obligations.”

Interest income. Interest income decreased to $0.2 million for the 2008 Quarter from $0.6 million for the 2007 Quarter. The decrease of $0.4 million resulted from decreased interest income earned on short-term investments, which were substantially liquidated to fund increased capital expenditures.

Transportation revenues and expenses. Transportation revenues and expenses each increased to $11.0 million for the 2008 Quarter compared to $10.6 million for the 2007 Quarter. The increase of $0.4 million was primarily attributable to higher average transportation rates which were 9.4% higher on a per ton basis in the 2008 Quarter compared to the 2007 Quarter. The cost of transportation services are passed through to our customers. Consequently, we do not realize any gain or loss on transportation revenues.

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Income before income taxes and minority interest. Income before income taxes and minority interest for the 2008 and 2007 Quarters was $36.7 million and $46.8 million, respectively, and reflects the impact of the changes in revenues and expenses described above.

Income tax expense (benefit). Income tax benefit for the 2008 Quarter was $0.1 million compared to income tax expense of $0.7 million for the 2007 Quarter. The income tax benefit for the 2008 Quarter was primarily due to operating losses associated with Matrix Design, a business owned by our subsidiary, Alliance Services, Inc. (“ASI”). For the 2007 Quarter income tax expense, ASI received a material amount of income from services we provided to a third-party coal synfuel facility, which ceased operations on December 31, 2007 with the expiration of the synfuel tax credits Our synfuel-related arrangements are discussed in more detail above under “–Summary.”

Minority interest. In March 2006 our subsidiary, White County Coal and Alexander J. House (“House”) entered into a limited liability company agreement to form MAC. MAC was formed to engage in the development and operation of a rock dust mill and to manufacture and sell rock dust. We consolidate MAC’s financial results in accordance with FASB Interpretation (“FIN”) No. 46R, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. Based on the guidance in FIN No. 46R, we concluded that MAC is a variable interest entity and that we are the primary beneficiary. House’s portion of MAC’s net income was $102,000 for the 2008 Quarter and a net loss of $85,000 for the 2007 Quarter and is recorded as minority interest on our condensed consolidated income statement.

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Segment Adjusted EBITDA. Our 2008 Quarter Segment Adjusted EBITDA decreased $1.3 million, or 1.6%, to $77.5 million from 2007 Quarter Segment Adjusted EBITDA of $78.8 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are (in thousands):

	Three Months Ended June 30,						Increase/(Decrease)
	2008			2007
Segment Adjusted EBITDA
Illinois Basin	$	47,306		$	46,372		$	934		2.0	%
Central Appalachia		16,927			26,489			(9,562	)	(36.1	)%
Northern Appalachia		7,613			5,655			1,958		34.6	%
Other and Corporate		5,757			270			5,487		(1	)
Elimination		(102	)		—			(102	)	(1	)
Total Segment Adjusted EBITDA (2)	$	77,501		$	78,786		$	(1,285	)	(1.6	)%
Tons sold
Illinois Basin		4,959			4,503			456		10.1	%
Central Appalachia		866			919			(53	)	(5.8	)%
Northern Appalachia		797			857			(60	)	(7.0	)%
Other and Corporate		—			—			—		—
Elimination		—			—			—		—
Total tons sold		6,622			6,279			343		5.5	%
Coal sales
Illinois Basin	$	168,656		$	153,170		$	15,486		10.1	%
Central Appalachia		52,736			52,394			342		0.7	%
Northern Appalachia		40,175			35,874			4,301		12.0	%
Other and Corporate		—			926			(926	)	(1	)
Elimination		—			—			—		—
Total coal sales	$	261,567		$	242,364		$	19,203		7.9	%
Other sales and operating revenues
Illinois Basin	$	145		$	7,594		$	(7,449	)	(98.1	)%
Central Appalachia		—			—			—		—
Northern Appalachia		1,094			1,070			24		2.2	%
Other and Corporate		5,174			2,548			2,626		(1	)
Elimination		(2,763	)		(873	)		(1,890	)	(1	)
Total other sales and operating revenues	$	3,650		$	10,339		$	(6,689	)	(64.7	)%
Segment Adjusted EBITDA Expense
Illinois Basin	$	121,495		$	114,392		$	7,103		6.2	%
Central Appalachia		38,599			37,396			1,203		3.2	%
Northern Appalachia		33,656			31,289			2,367		7.6	%
Other and Corporate		4,575			3,204			1,371		42.8	%
Elimination		(2,660	)		(873	)		(1,787	)	(1	)
Total Segment Adjusted EBITDA Expense (3)	$	195,665		$	185,408		$	10,257		5.5	%

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

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

• the financial performance of the ARLP Partnership’s assets without regard to financing methods, capital structure or historical cost basis;

• the ability of the ARLP Partnership’s assets to generate cash sufficient to pay interest costs and support its indebtedness;

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

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

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

The following is a reconciliation of Segment Adjusted EBITDA to net income (in thousands):

	Three Months Ended June 30,
	2008			2007
Segment Adjusted EBITDA	$	77,501		$	78,786
General and administrative		(12,119	)		(8,266	)
Depreciation, depletion and amortization		(25,600	)		(21,425	)
Interest expense, net		(3,053	)		(2,273	)
Income tax (expense) benefit		70			(670	)
Minority interest (expense)		(102	)		85
Net income	$	36,697		$	46,237

(3) Segment Adjusted EBITDA Expense includes operating expenses, outside 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 purchases are included in Segment Adjusted EBITDA Expense because tons sold and coal sales include sales from outside purchases.

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

	Three Months Ended June 30,
	2008			2007
Segment Adjusted EBITDA Expense	$	195,665		$	185,408
Outside purchases		(4,552	)		(7,607	)
Other income		250			167
Operating expense	$	191,363		$	177,968

Illinois Basin – Segment Adjusted EBITDA, as defined in reference (2) to the table above, increased 2.0% or $0.9 million to $47.3 million in the 2008 Quarter, from $46.4 million in the 2007 Quarter. This increase was primarily the result of increased coal sales and the $1.9 million gain on settlement of claims relating to the Pattiki Vertical Belt Incident as discussed above, partially offset by the loss of synfuel related benefits. The increase in coal sales in the 2008 Quarter of $15.5 million or 10.1%, to $168.7 million, as compared to $153.2 million in the 2007 Quarter reflects an increase of 0.5 million tons sold to 5.0 million in the 2008 Quarter compared to 4.5 million tons in the 2007 Quarter, which was driven by increased production primarily from the Elk Creek mine. Other sales and operating revenues decreased $7.4 million primarily due to the expiration of the non-conventional synfuel-related tax credits on December 31, 2007 and the resulting loss of benefits derived from supplying third-party coal synfuel facilities with coal feedstock and related services. Our synfuel-related arrangements are discussed in more detail above under “–Summary.” Segment Adjusted EBITDA Expense, as defined in reference (3) to the above table, for the 2008 Quarter increased 6.2% to $121.5 million from $114.4 million in the 2007 Quarter. The increase in the 2008 Quarter Segment Adjusted EBITDA Expense compared to the 2007 Quarter reflects the impact of the cost increases described above under consolidated operating expenses and costs associated with higher produced tons sold, partially offset by the gain on settlement of claims relating to the Pattiki Vertical Belt Incident.

Central Appalachia – Segment Adjusted EBITDA as defined in reference (2) to the table above, decreased $9.6 million to $16.9 million for the 2008 Quarter compared to the 2007 Quarter Segment Adjusted EBITDA of $26.5 million. The decrease was primarily the result of the net gain from insurance settlement of approximately $11.5 million and a reduction in operating expenses of approximately $0.8 million for the 2007 Quarter related to the MC Mining Fire Incident as compared to a $2.8 million gain recognized in the 2008 Quarter on settlement of claims from the third-party that provided security services at the time of the fire. Please read “–MC Mining Mine Fire” below. Due to improved contract pricing and increased sales into a higher priced spot market, average coal sales price increased 6.8% to $60.89 per ton in the 2008 Quarter, as compared to $57.00 per ton in the 2007 Quarter. Segment Adjusted EBITDA Expense, as defined in reference (3) to the above table, for the 2008 Quarter increased 3.2% to $38.6 million from $37.4 million in the 2007 Quarter. The Segment Adjusted EBITDA Expense per ton sold during the 2008 Quarter was $44.57, an increase of $3.88 per ton, or 9.5%, as compared to $40.69 per ton in the 2007 Quarter. The increased Segment Adjusted EBITDA Expense was primarily a result of higher operating expenses associated with compliance with the new mine safety standards and higher labor expenses per ton, as well as other cost increases described above under consolidated operating expenses.

Northern Appalachia – Segment Adjusted EBITDA, as defined in reference (2) to the table above, increased 34.6%, to $7.6 million for the 2008 Quarter as compared to the 2007 Quarter Segment Adjusted EBITDA of $5.7 million. The increase was primarily attributable to higher average coal sales price of $50.43 per ton during the 2008 Quarter as compared to $41.84 per ton during the

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2007 Quarter, resulting from higher priced sales in the spot and export markets during the 2008 Quarter. This increase in coal sales prices was partially offset by a higher Segment Adjusted EBITDA Expense per ton sold during the 2008 Quarter of $42.25, an increase of $5.76 per ton, or 15.8%, as compared to $36.49 per ton in the 2007 Quarter (for a definition of Segment Adjusted EBITDA Expense, see reference (3) to the above table). The increase in Segment Adjusted EBITDA Expense per ton sold was primarily a result of higher purchased coal expense and lower production in the 2008 Quarter reflecting adverse mining conditions, reduced saleable coal recoveries and reduced productivity from our third-party mining operations, partially offset by lower maintenance costs in the 2008 Quarter.

Other and Corporate – Segment Adjusted EBITDA, as defined in reference (2) to the above table, increased to $5.8 million in the 2008 Quarter from $0.3 million in the 2007 Quarter primarily due to the $5.2 million gain on sale of non-core coal reserves in the 2008 Quarter. The increase in Segment Adjusted EBITDA Expense, as defined in reference (3) to the above table, primarily reflects increased expenses associated with higher outside services revenue and product sales, partially offset by the elimination of coal sales and related operating expenses attributable to non-recurring coal brokerage activity associated with the ICG agreement discussed above under consolidated operating expenses.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

We reported net income of $79.9 million for the 2008 Period compared to $91.8 million for the 2007 Period. This decrease of $11.9 million was principally due to the significant items discussed above at the beginning of “Results of Operations” and higher depreciation, depletion and amortization resulting from capital expenditures associated with ARLP’s growth initiatives, partially offset by improved coal sales. We had record tons sold of 13.6 million and tons produced of 13.3 million for the 2008 Period compared to 12.5 million tons sold and 12.2 million tons produced for the 2007 Period. Increased operating expenses during the 2008 Period primarily reflect the increase in record tons produced and higher sales related expenses resulting from record tons sold, as well as higher regulatory compliance costs and other factors described below.

	Six Months Ended June 30,
	2008		2007		2008		2007
	(in thousands)				(per ton sold)
Tons sold		13,616		12,457		N/A		N/A
Tons produced		13,332		12,195		N/A		N/A
Coal sales	$	530,725	$	481,234	$	38.98	$	38.63
Operating expenses and outside purchases	$	391,436	$	358,830	$	28.75	$	28.81

Coal sales. Coal sales for the 2008 Period increased 10.3% to $530.7 million from $481.2 million for the 2007 Period. The increase of $49.5 million reflected record tons sold of 13.6 million (contributing $44.7 million of the increase) for the 2008 Period compared to 12.5 million for the 2007 Period and higher average coal sales prices (contributing $4.8 million of the increase). Record tons produced increased 9.3% to 13.3 million tons for the 2008 Period from 12.2 million tons for the 2007 Period.

Operating expenses. Operating expenses increased 11.3% to $384.0 million for the 2008 Period from $345.0 million for the 2007 Period. The increase of $39.0 million resulted from the impact of the following specific factors:

• Higher operating expenses associated with an additional 1,420,000 produced tons sold;

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• Labor and benefit expenses per ton produced decreased to $9.73 per ton in the 2008 Period from $9.90 per ton in the 2007 Period reflecting decreased workers’ compensation costs partially offset by increased headcount due to capacity expansion, pay rate and benefit increases and increased health care costs;

• Material and supplies, and maintenance expenses per ton produced increased 5.2% and 2.7%, respectively, to $9.45 and $3.09 per ton, respectively, in the 2008 Period from $8.98 and $3.01 per ton, respectively, in the 2007 Period. The respective increases of $0.47 and $0.08 per ton produced resulted from increased costs for certain products and services (particularly roof support, seals, power and fuel) used in the mining process and higher regulatory compliance costs which also contributed to increased mine administrative expenses;

• Production taxes and royalties (which are incurred as a percentage of coal sales revenue or volumes) increased $2.4 million as a result of increased tons sold and increased average coal sales prices;

• Reduced expenses of $6.0 million in the 2008 Period as compared to the 2007 Period were associated with the purchase and sale of coal during the 2007 Period under a settlement agreement we entered into with ICG in November 2005. For more information, please read our Annual Report on Form 10-K for the year ended December 31, 2007, “Other” under “Item 8. Financial Statements and Supplementary Data – Note 19. Commitments and Contingencies.” Consistent with the guidance in EITF No. 04-13, Pontiki Coal’s sale of coal to ICG and Alliance Coal’s purchase of coal from ICG pursuant to that settlement agreement are combined. Therefore, the excess of Alliance Coal’s purchase price from ICG over Pontiki Coal’s sales price to ICG is reported as an operating expense. We fully satisfied our coal sales agreement with ICG in April 2007;

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

• The 2007 Period includes a $0.8 million reduction in operating expenses as a result of the final insurance settlement of the MC Mining Fire Incident. Please read “–MC Mining Mine Fire” below.

General and administrative. General and administrative expenses for the 2008 Period increased to $21.0 million compared to $16.2 million in the 2007 Period. The increase was primarily due to higher salary and benefit costs related to increased staffing levels and higher incentive and unit-based compensation expense.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, products and services provided by MAC and Matrix Design Group, and other outside services and administrative services revenue from affiliates. The 2007 Period also includes rental and service fees from third-party coal synfuel facilities. Other sales and operating revenues decreased to $7.5 million for the 2008 Period from $19.9 million for the 2007 Period. The decrease of $12.4 million was primarily attributable to the loss of synfuel-related benefits due to the expiration of the non-conventional synfuel tax credits on December 31, 2007, partially offset by increased revenues from transloading services and MAC product sales. Our synfuel-related arrangements are discussed in more detail above under “–Summary.”

Outside purchases. Outside purchases decreased to $7.5 million for the 2008 Period from $13.9 million in the 2007 Period. The decrease of $6.4 million was primarily attributable to a decrease in outside purchases at our Illinois Basin and Central Appalachian regions partially offset by increased outside purchases in the Northern Appalachian region to supply attractive opportunities in the spot and export markets.

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Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $48.9 million for the 2008 Period from $41.2 million for the 2007 Period. The increase of $7.7 million was primarily attributable to additional depreciation expense associated with continuing capital expenditures related to infrastructure improvements, efficiency projects and expansion of production capacity.

Interest expense. Interest expense, net of capitalized interest increased to $6.2 million for the 2008 Period from $5.7 million for the 2007 Period. The increase of $0.5 million was principally attributable to the increase interest expense due to increased borrowings under the revolving credit facility in addition to interest expense incurred on our recently completed $350 million private placement of senior notes, partially offset by reduced interest expense from our August 2007 principal payment of $18.0 million on our existing senior notes. Our recently completed $350 million private placement of senior notes is discussed in more detail below under “–Debt Obligations.”

Interest income. Interest income decreased to $0.3 million for the 2008 Period from $1.1 million for the 2007 Period. The decrease of $0.8 million resulted from decreased interest income earned on short-term investments, which were substantially liquidated to fund increased capital expenditures.

Transportation revenues and expenses. Transportation revenues and expenses each increased to $21.6 million for the 2008 Period compared to $19.3 million for the 2007 Period. The increase of $2.3 million was primarily attributable to a 5.9% increase in average transportation rates on a per ton basis in the 2008 Period compared to the 2007 Period and higher transported coal volumes of 4.5 million tons in the 2008 Period compared to 4.3 million tons in the 2007 Period. The cost of transportation services are passed through to our customers. Consequently, we do not realize any gain or loss on transportation revenues.

Income before income taxes and minority interest. Income before income taxes and minority interest for the 2008 and 2007 Periods were $79.4 million and $92.9 million, respectively, and reflects the impact of the changes in revenues and expenses described above.

Income tax expense (benefit). Income tax benefit for the 2008 Period was $0.7 million compared to income tax expense of $1.2 million for the 2007 Period. The income tax benefit for the 2008 Period was primarily due to operating losses associated with Matrix Design, a business owned by our subsidiary, ASI. For the 2007 Period income tax expense, ASI received a material amount of income from services we provided to a third-party coal synfuel facility, which ceased operations on December 31, 2007 with the expiration of the synfuel tax credits Our synfuel-related arrangements are discussed in more detail above under “–Summary.”

Minority interest. In March 2006 our subsidiary, White County Coal and House entered into a limited liability company agreement to form MAC. MAC was formed to engage in the development and operation of a rock dust mill and to manufacture and sell rock dust. We consolidate MAC’s financial results in accordance with FIN No. 46R. Based on the guidance in FIN No. 46R, we concluded that MAC is a variable interest entity and that we are the primary beneficiary. House’s portion of MAC’s net income was $243,000 for the 2008 Period and a net loss of $167,000 for the 2007 Period and is recorded as minority interest on our condensed consolidated income statement.

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Segment Adjusted EBITDA. Our 2008 Period Segment Adjusted EBITDA increased $0.4 million to $155.2 million from the 2007 Period Segment Adjusted EBITDA of $154.8 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,
	2008			2007			Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	104,756		$	102,868		$	1,888		1.8	%
Central Appalachia		28,049			36,836			(8,787	)	(23.9	)%
Northern Appalachia		16,611			14,515			2,096		14.4	%
Other and Corporate		5,731			605			5,126		(1	)
Elimination		18			—			18		(1	)
Total Segment Adjusted EBITDA (2)	$	155,165		$	154,824		$	341		0.2	%
Tons sold
Illinois Basin		10,324			9,031			1,293		14.3	%
Central Appalachia		1,712			1,757			(45	)	(2.6	)%
Northern Appalachia		1,580			1,669			(89	)	(5.3	)%
Other and Corporate		—			—			—		—
Elimination		—			—			—		—
Total tons sold		13,616			12,457			1,159		9.3	%
Coal sales
Illinois Basin	$	352,559		$	308,363		$	44,196		14.3	%
Central Appalachia		101,846			95,389			6,457		6.8	%
Northern Appalachia		76,320			70,398			5,922		8.4	%
Other and Corporate		—			7,084			(7,084	)	(1	)
Elimination		—			—			—		—
Total coal sales	$	530,725		$	481,234		$	49,491		10.3	%
Other sales and operating revenues
Illinois Basin	$	718		$	15,284		$	(14,566	)	(95.3	)%
Central Appalachia		161			72			89		(1	)
Northern Appalachia		2,140			2,074			66		3.2	%
Other and Corporate		9,120			4,583			4,537		99.0	%
Elimination		(4,679	)		(2,152	)		(2,527	)	(1	)
Total other sales and operating revenues	$	7,460		$	19,861		$	(12,401	)	(62.4	)%
Segment Adjusted EBITDA Expense
Illinois Basin	$	248,521		$	220,778		$	27,743		12.6	%
Central Appalachia		76,748			70,117			6,631		9.5	%
Northern Appalachia		61,849			57,957			3,892		6.7	%
Other and Corporate		8,547			11,062			(2,515	)	(22.7	)%
Elimination		(4,696	)		(2,152	)		(2,544	)	(1	)
Total Segment Adjusted EBITDA Expense (3)	$	390,969		$	357,762		$	33,207		9.3	%

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

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

• the financial performance of the ARLP Partnership’s assets without regard to financing methods, capital structure or historical cost basis;

• the ability of the ARLP Partnership’s assets to generate cash sufficient to pay interest costs and support its indebtedness;

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

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

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

The following is a reconciliation of Segment Adjusted EBITDA to net income (in thousands):

	Six Months Ended June 30,
	2008			2007
Segment Adjusted EBITDA	$	155,165		$	154,824
General and administrative		(20,950	)		(16,195	)
Depreciation, depletion and amortization		(48,894	)		(41,218	)
Interest expense, net		(5,943	)		(4,557	)
Income tax (expense) benefit		725			(1,244	)
Minority interest (expense)		(243	)		167
Net income	$	79,860		$	91,777

(3) Segment Adjusted EBITDA Expense includes operating expenses, outside 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 purchases are included in Segment Adjusted EBITDA Expense because tons sold and coal sales include sales from outside purchases.

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

	Six Months Ended June 30,
	2008			2007
Segment Adjusted EBITDA Expense	$	390,969		$	357,762
Outside purchases		(7,455	)		(13,873	)
Other income		467			1,068
Operating expense	$	383,981		$	344,957

Illinois Basin – Segment Adjusted EBITDA, as defined in reference (2) to the table above, increased 1.8% to $104.8 million for the 2008 Period from the 2007 Period Segment Adjusted EBITDA of $102.9 million. The increase of $1.9 million was primarily attributable to increased coal sales and the $1.9 million gain on settlement of claims relating to the Pattiki Vertical Belt Incident, as discussed above under consolidated operating expense, partially offset by the loss of synfuel related benefits and higher operating expenses. The increased coal sales in the 2008 Period, which rose by $44.2 million, or 14.3%, to $352.6 million as compared to $308.4 million in the 2007 Period, resulted from increased tons sold of 1.3 million tons. The increased tons sold primarily resulted from increased production capacity at the Elk Creek mine, increased production at the Warrior and Gibson mines and higher sales from inventory as compared to the 2007 Period. Other sales and operating revenues decreased $14.6 million, primarily due to the expiration of the non-conventional synfuel-related tax credits on December 31, 2007 and the resulting loss of benefits derived from supplying third-party coal synfuel facilities with coal feedstock and related services. Please read “–Summary” above for a discussion regarding the status of third-party coal synfuel facilities. Total Segment Adjusted EBITDA Expense, as defined in reference (3) to the above table, for the 2008 Period increased 12.6% to $248.5 million from $220.8 million in the 2007 Period. The increase in the 2008 Period Segment Adjusted EBITDA Expense compared to the 2007 Period reflects the impact of the cost increases described above under consolidated operating expenses and costs associated with higher produced tons sold, partially offset by the gain on settlement of claims relating to the Pattiki Vertical Belt Incident.

Central Appalachia – Segment Adjusted EBITDA, as defined in reference (2) to the table above, decreased $8.8 million, or 23.9%, to $28.0 million for the 2008 Period as compared to the 2007 Period Segment Adjusted EBITDA of $36.8 million. This decrease was primarily the result of the net gain from insurance settlement of approximately $11.5 million and a reduction in operating expenses of approximately $0.8 million in the 2007 Period related to the MC Mining Fire Incident, as compared to a $2.8 million gain recognized in the 2008 Period on settlement of claims from the third-party that provided security services at the time of the fire. Please read “–MC Mining Mine Fire” below. Coal sales for the 2008 and 2007 Periods were $101.8 million and $95.4 million, respectively. The increase of $6.4 million primarily reflects a higher average coal sales price per ton of $59.50 in the 2008 Period as compared to $54.27 in the 2007 Period, an increase of $5.23 per ton, or 9.6%. Segment Adjusted EBITDA Expense, as defined in reference (3) to the above table, for the 2008 Period increased 9.5% to $76.7 million from $70.1 million in the 2007 Period. The Segment Adjusted EBITDA Expense per ton during the 2008 Period was $44.84, an increase of $4.95 per ton, or 12.4% over the 2007 Period Segment Adjusted EBITDA Expense per ton of $39.89. The increase in Segment Adjusted EBITDA Expense per ton was primarily a result of higher operating expenses associated with the new mine safety standards and increased labor expense, as well as other cost increases described above under consolidated operating expenses.

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Northern Appalachia – Segment Adjusted EBITDA, as defined in reference (2) to the table above, increased 14.4%, to $16.6 million for the 2008 Period as compared to the 2007 Period Segment Adjusted EBITDA of $14.5 million. The increase in Segment Adjusted EBITDA of $2.1 million was primarily attributable to higher average sales price of $48.30 per ton during the 2008 Period as compared to $42.18 per ton during the 2007 Period, resulting from higher priced sales in the spot and export markets. Segment Adjusted EBITDA Expense per ton sold during the 2008 Period of $39.14 was an increase of $4.41 per ton, or 12.7%, as compared to $34.73 per ton in the 2007 Period (for a definition of Segment Adjusted EBITDA Expense, see reference (3) to the above table). The increase in Segment Adjusted EBITDA Expense per ton sold was primarily a result of higher purchased coal expense and lower production in the 2008 Period, partially offset by lower maintenance costs in the 2008 Period. The decreased production in the 2008 Period compared to the 2007 Period reflects adverse conditions, reduced saleable coal recoveries and reduced productivity from our third-party mining operations in the 2008 Period, combined with accelerated continuous miner production in the 2007 Period associated with the transition to the Mountain View mine.

Other and Corporate – Segment Adjusted EBITDA, as defined in reference (2) to the above table, increased to $5.7 million in the 2008 Period from $0.6 million in the 2007 Period primarily due to the $5.2 million gain on sale of non-core coal reserves in the 2008 Period. The decrease in Segment Adjusted EBITDA Expense, as defined in reference (3) to the above table, primarily reflects the elimination of coal sales revenue and related operating expenses attributable to non-recurring coal brokerage activity associated with the ICG agreement discussed above under consolidated operating expenses, partially offset by increased expenses associated with higher outside services revenue and product sales.

MC Mining Mine Fire

On June 18, 2007, we agreed to a full and final resolution of our insurance claims relating to a mine fire that occurred on or about December 25, 2004 at our MC Mining’s Excel No. 3 mine. This resolution included settlement of all expenses, losses and claims we incurred for the aggregate amount of $31.6 million, inclusive of $8.2 million of various deductibles and co-insurance, netting to $23.4 million of insurance proceeds paid to us. In 2006 and 2005, we received partial advance payments on the claims totaling $16.2 million, part of which we recognized as an offset to operating expenses ($0.4 million and $10.7 million in the three months ended March 31, 2006 and the year ended December 31, 2005, respectively), with the remaining $5.1 million of partial payments previously included in other current liabilities pending final claim resolution. In June 2007, as a result of this final resolution, we received additional cash payments of $7.2 million and recognized a net gain from insurance settlement of approximately $11.5 million, as well as a reduction in operating expenses of approximately $0.8 million. In May 2008, we realized a $2.8 million gain on settlement of claims from the third-party that provided security services at the time of the fire.

Liquidity and Capital Resources

Cash Flows

Cash provided by operating activities was $150.8 million for the 2008 Period compared to $141.4 million for the 2007 Period. The increase in cash provided by operating activities was principally attributable to favorable changes in operating assets and liabilities.

Net cash used in investing activities was $72.1 million for the 2008 Period compared to $129.9 million for the 2007 Period. The decrease in use of cash was primarily attributable to our acquisition of coal reserves in Webster and Hopkins County, Kentucky for $53.3 million in the 2007 Period, partially offset by our acquisition of additional rights to coal reserves located in western Kentucky for $13.3 million in the 2008 Period. See Note 3. Acquisitions to the Unaudited Condensed Consolidated Financial Statements

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included in “Item 1. Financial Statement (Unaudited)” of this Quarterly Report on Form 10-Q. Additionally, we received proceeds of $7.2 million in the 2008 Period from the sale of coal reserves and timing differences in accounts payable and accrued liabilities related to capital expenditures.

Net cash provided by financing activities was $281.6 million for the 2008 Period compared to net cash used in financing activities of $30.6 million for the 2007 Period. The increase in cash provided by financing activities primarily was attributable to the proceeds from the recently completed $350 million private placement of senior notes (see “–Debt Obligations” below) and increased net borrowings under the revolving credit facilities, partially offset by an increase in distributions paid to partners in the 2008 Period.

Capital Expenditures

Capital expenditures were comparable for the 2008 and 2007 Periods at $71.0 million and $69.2 million, respectively.

Including capital development for our River View mine, our total capital expenditures for 2008 are estimated to be from $200.0 to $220.0 million. We will continue to have significant capital requirements over the long-term, which may require us to incur additional debt or seek additional equity capital. Management anticipates funding short-term capital requirements by a variety of sources, including cash flows from operating activities, cash provided by the recently completed $350 million private placement of senior notes (see “–Debt Obligations” below) and borrowings available under our revolving credit facility. Based on our recent operating results, current cash position, anticipated future cash flows and sources of financing, we do not expect to experience any significant liquidity constraints in the foreseeable future.

Debt Obligations

Credit Facility. On September 25, 2007 our Intermediate Partnership entered into a $150.0 million revolving credit facility (“ARLP Credit Facility”), which matures in 2012. Borrowings under the ARLP Credit Facility bear interest based on a floating base rate plus an applicable margin. The applicable margin is based on a leverage ratio of our Intermediate Partnership, as computed from time to time. For London Interbank Offered Rate (“LIBOR”) borrowings, the applicable margin under the ARLP Credit Facility ranges from 0.625% to 1.150% over LIBOR. As of June 30, 2008, the applicable margin for borrowings under the ARLP Credit Facility was 0.75% over LIBOR and the interest rate on the ARLP Credit Facility was 3.23%. Letters of credit can be issued under the ARLP Credit Facility not to exceed $100.0 million. Outstanding letters of credit reduce amounts available under the ARLP Credit Facility. At June 30, 2008, we had $21.5 million of borrowings and $27.6 million of letters of credit outstanding with $100.9 million available for borrowing under the ARLP Credit Facility. We incur a commitment fee of 0.175% on the undrawn portion of the ARLP Credit Facility.

Senior Notes. Our Intermediate Partnership has $126.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in seven remaining equal annual installments of $18.0 million with interest payable semi-annually (“Senior Notes”).

Series A Senior Notes. On June 26, 2008, our Intermediate Partnership entered into a Note Purchase Agreement (the “2008 Note Purchase Agreement”) with a group of institutional investors in a private placement offering. We issued $205.0 million of Series A Senior Notes, which bear interest at 6.28% and mature on June 26, 2015, with interest payable semi-annually.

Series B Senior Notes. On June 26, 2008, we issued under the 2008 Note Purchase Agreement $145.0 million of Series B Senior Notes, which bear interest at 6.72% and mature on June 26, 2018 with interest payable semi-annually.

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The proceeds from the Series A and Series B Senior Notes (collectively, the “2008 Senior Notes”) will be used to repay the current amounts outstanding under the ARLP Credit Facility, to pay expenditures associated with the development of the River View mining complex (currently estimated to be $250 to $275 million over the 2008 – 2010 time frame), to pay expenses associated with the offering of the 2008 Senior Notes and for other general working capital requirements. We incurred debt issuance costs of approximately $1.5 million associated with the 2008 Senior Notes, which have been deferred and will be amortized as a component of interest expense over the term of the respective notes.

The ARLP Credit Facility, Senior Notes and 2008 Senior Notes (collectively “ARLP Debt Arrangements”) are guaranteed by all of the 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 relative to its annual production. In addition, the ARLP Debt Arrangements require our Intermediate Partnership to comply with certain financial ratios, including a maximum leverage ratio and a minimum interest coverage ratio. We were in compliance with the covenants of the ARLP Debt Arrangements as of June 30, 2008.

Other. We maintain agreements with two banks to provide additional letters of credit in an aggregate amount of $31.0 million to maintain surety bonds to secure certain asset retirement obligations and our obligations for workers’ compensation benefits. At June 30, 2008, we had $30.6 million in letters of credit outstanding under these agreements. Our special general partner guarantees $5.0 million of these outstanding letters of credit.

On March 19, 2007, MAC entered into a secured line of credit (“LOC”) with a third-party, which was scheduled to expire on March 19, 2008. In September 2007, MAC entered into a $1.5 million Revolving Credit Agreement (“Revolver”) with ARLP. Concurrent with the execution of the Revolver, MAC repaid all amounts outstanding under the LOC. By amendment effective April 1, 2008, the term of the Revolver was extended to June 30, 2009. Due to the consolidation of MAC in accordance with FIN No. 46R, the intercompany transactions associated with the Revolver are eliminated.

Related-Party Transactions

We have continuing related-party transactions with our managing general partner, AHGP, and our special general partner, including our special general partner’s affiliates. These related-party transactions relate principally to the provision of administrative services to AHGP and Alliance Resource Holdings II, Inc. and their respective affiliates, mineral and equipment leases with our special general partner and its affiliates, and guarantees from our special general partner for letters of credit.

Please read our Annual Report on Form 10-K for the year ended December 31, 2007, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Related-Party Transactions” for additional information concerning the related-party transactions described above.

On January 28, 2008, we acquired, through our subsidiary Alliance Resource Properties, additional rights to approximately 48.2 million tons of coal reserves located in western Kentucky from SGP Land, LLC (“SGP Land”) for $13.3 million cash paid at closing. SGP Land is a subsidiary of our special general partner and is indirectly owned by Mr. Craft. At the time of our acquisition, these reserves were leased by SGP Land to our subsidiaries, Webster County Coal, Warrior Coal and Hopkins County Coal through mineral leases and sublease agreements. For more information, please read Part I. “Item 1. Financial Statements (Unaudited) – Note 3. Acquisitions” of this Quarterly Report on Form 10-Q.

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Because the transaction described above was a related-party transaction, it was reviewed by the Board of Directors and its conflicts committee and determined to be fair and reasonable to us and our limited partners. Because the acquisition was between entities under common control, it was accounted for at historical cost.

New Accounting Standards

New Accounting Standards Issued and Adopted

In September 2006, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements. This standard defines fair value, establishes a framework for measuring fair value in accounting principles generally accepted in the United States of America, and expands disclosure about fair value measurements. SFAS No. 157 applies under other accounting standards that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurement. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 with the exception of nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value on a nonrecurring basis for which the requirements of SFAS No. 157 have been deferred by the FASB for one year. The adoption of SFAS No. 157 on January 1, 2008 did not have a material impact on our condensed consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 allows entities to choose to measure at fair value financial instruments and certain other eligible items which are not otherwise currently required to be measured at fair value. Under SFAS No. 159, the decision to measure items at fair value is made at specified election dates on an irrevocable instrument-by-instrument basis. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We have not elected to present any of our financial assets or liabilities currently recorded on our condensed consolidated balance sheet at fair value under SFAS No. 159, therefore, the adoption of SFAS No. 159 on January 1, 2008 did not have a material impact on our condensed consolidated financial statements.

New Accounting Standards Issued and Not Yet Adopted

In December 2007, the FASB issued SFAS No. 141R, Business Combinations, and SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements. SFAS Nos. 141R and 160 require most identifiable assets, liabilities, noncontrolling interests and goodwill acquired in a business combination to be recorded at “full fair value” and require noncontrolling interests (previously referred to as minority interests) to be reported as a component of equity, which changes the accounting for transactions with noncontrolling interest holders. Both statements are effective for periods beginning on or after December 15, 2008 and earlier adoption is prohibited. SFAS No. 141R will be applied to business combinations occurring after the effective date and SFAS No. 160 will be applied prospectively to all noncontrolling interests, including any that arose before the effective date. We are currently evaluating the requirements of SFAS Nos. 141R and 160 and have not yet determined the impact on our condensed consolidated financial statements.

In March 2008, the FASB issued EITF No. 07-4, which considers whether the IDR of a master limited partnership represents a participating security when considered in the calculation of earnings per unit under the two-class method. The EITF considers whether the partnership agreement contains any contractual limitations concerning distributions to IDR holders that would impact the amount of earnings to allocate to the IDR holders for each reporting period. If distributions are contractually limited to the IDR

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holders’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the IDR holders. In addition, the EITF presents alternative methods for inclusion of IDR in the earnings per unit computation. When cash distributions exceed net income for the period, net income should be reduced by the distributions made to the holders of the general partner interest, the holder of the limited partner interest and IDR holders for the period. The provisions of EITF No. 07-4 are effective for fiscal years beginning after December 15, 2008. We expect the adoption of EITF No. 07-4 will impact our presentation of earnings per unit. We currently present earnings per unit as though all earnings were distributed each quarter. For more information, please read Part I. “Item 1. Financial Statements (Unaudited) – Note 7. “Net Income Per Limited Partner Unit” of this Quarterly Report on Form 10-Q. Under the new guidance of EITF No. 07-4, we believe our partnership agreement contractually limits our distributions to available cash and therefore undistributed earnings will no longer be allocated to the IDR holder upon adoption of EITF No. 07-4 effective January 1, 2009.

In June 2008, the FASB issued Staff Position (“FSP”) No. EITF No. 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities.” This FSP affects entities that accrue cash dividends on share-based payment awards during the awards’ service period when the dividends do not need to be returned if the employees forfeit the award. The FSP requires that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders and are considered participating securities. Because the awards are considered participating securities, the issuing entity is required to apply the two-class method of computing basic and diluted earnings per share. The provisions of FSP No. EITF No. 03-6-1 are effective for fiscal years beginning after December 15, 2008. We are currently evaluating the requirements of FSP No. EITF 03-6-1, to determine the impact, if any, on our consolidated financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

All of our transactions are denominated in U.S. dollars and, as a result, we do not have material exposure to currency exchange-rate risks. We do not have any interest rate, foreign currency exchange rate or commodity price-hedging transactions outstanding.

Borrowings under the ARLP Credit Facility are at variable rates and, as a result, we have interest rate exposure. Historically, our earnings have not been materially affected by changes in interest rates.

As of June 30, 2008, the estimated fair value of the Senior Notes and the 2008 Senior Notes was approximately $483.3 million. The fair values of long-term debt are estimated using discounted cash flow analyses, based upon our current incremental borrowing rates for similar types of borrowing arrangements as of June 30, 2008. There were no other significant changes in our quantitative and qualitative disclosures about market risk as set forth in our Annual Report on Form 10-K for the year ended December 31, 2007.

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ITEM 4. CONTROLS AND PROCEDURES

We maintain controls and procedures designed to ensure that information required to be disclosed in the reports we file with the U.S. Securities and Exchange Commission (“SEC”) is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act) was performed as of June 30, 2008. 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, 2008, there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 that are intended to come within the safe harbor protection provided by those sections. These statements are based on our beliefs as well as assumptions made by, and information currently available to, us. When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “may,” “project,” “will,” and similar expressions identify forward-looking statements. Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are reasonable, but are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ from those in the forward-looking statements are:

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

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

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

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

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

• customer bankruptcies and/or cancellations or breaches to existing contracts;

• customer delays or defaults in making payments;

• fluctuations in coal demand, prices and availability due to labor and transportation costs and disruptions, equipment availability, governmental regulations and other factors;

• our productivity levels and margins that we earn on our coal sales;

• greater than expected increases in raw material costs;

• greater than expected shortage of skilled labor;

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

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

• greater than expected environmental regulation, costs and liabilities;

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

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

• results of litigation, including claims not yet asserted;

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

• coal market’s share of electricity generation;

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

• legislation, regulatory and court decisions and interpretations thereof, including but not limited to issues related to climate change;

• the impact from provisions of The Energy Policy Act of 2005;

• the impact from provisions of or changes in enforcement activities associated with the Mine Improvement and New Emergency Response Act of 2006 as well as any subsequent federal or state legislation or regulations;

• replacement of coal reserves;

• a loss or reduction of direct or indirect benefits from certain state and federal 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 Item 1. “Legal Proceedings.”

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

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

• in this Quarterly Report on Form 10-Q;

• other reports filed by us with the SEC;

• our press releases; and

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

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PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The information in Note 2. Contingencies to the Unaudited Condensed Consolidated Financial Statements included in “Item 1. Financial Statements (Unaudited)” of this Quarterly Report on Form 10-Q herein is hereby incorporated by reference. See also “Item 3. Legal Proceedings” in the Annual Report on Form 10-K for the year ended December 31, 2007.

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, 2007 which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K and this Quarterly Report on Form 10-Q are not our only risks. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial based on current knowledge and factual circumstances, if such knowledge or facts change, also may materially adversely affect our business, financial condition and/or operating results in the future.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

10.1	Note Purchase Agreement, 6.28% Senior Notes Due June 26, 2015, and 6.72% Senior Notes due June 26, 2018, dated as of June 26, 2008, by and among Alliance Resource Operating Partners, L.P. and various investors (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed with the Commission on July 1, 2008).
10.2	First Amendment, dated as of June 26, 2008, to the Note Purchase Agreement, 8.31% Senior Notes due August 20, 2014, by and among Alliance Resource Operating Partners, L.P. (as successor to Alliance Resource GP, LLC) and various investors. (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K filed with the Commission on July 1, 2008).

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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, 2008, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated August 8, 2008, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated August 8, 2008, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated August 8, 2008, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	Letter Amendment No. 1, dated as of June 26, 2008, to the Second Amended and Restated Credit Agreement, dated as of September 25, 2007, among Alliance Resource Operating Partners, L.P. as Borrower, the Initial Lenders, Initial Issuing Banks and Swing Line Bank, in each case as named therein, JPMorgan Chase Bank, N.A. as Paying Agent,, Citicorp USA, Inc. and JPMorgan Chase Bank, N.A. as Co-Administrative Agents,, and Citigroup Global Markets Inc. and J.P. Morgan Securities, Inc. as Joint Lead Arrangers and Joint Bookrunners. (Incorporated by reference to Exhibit 99.1 of the Registrant’s Current Report on Form 8-K filed with the Commission on July 1, 2008).

* Filed herewith.

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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, 2008.

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
	/s/ Brian L. Cantrell
	Brian L. Cantrell
	Senior Vice President and Chief Financial Officer

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