Edgar Filing: ALLIANCE RESOURCE PARTNERS LP

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2008

¨	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 May 12, 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 March 31, 2008 and December 31, 2007	1

	Condensed Consolidated Statements of Income for the three months ended March 31, 2008 and 2007	2

	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 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	14

ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	24

ITEM 4.	Controls and Procedures	24

	Forward-Looking Statements	25

PART II

OTHER INFORMATION


ITEM 1.	Legal Proceedings	27

ITEM 1A.	Risk Factors	27

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	27

ITEM 3.	Defaults upon Senior Securities	27

ITEM 4.	Submission of Matters to a Vote of Security Holders	27

ITEM 5.	Other Information	27

ITEM 6.	Exhibits	27

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)


	March 31, 2008			December 31, 2007
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	15,896		$	1,118
Trade receivables		105,461			92,667
Other receivables		2,715			3,399
Due from affiliates		124			139
Inventories		27,904			26,100
Advance royalties		4,452			4,452
Prepaid expenses and other assets		6,072			9,099

Total current assets		162,624			136,974

PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost		990,591			948,210
Less accumulated depreciation, depletion and amortization		(448,789	)		(427,572	)

Total property, plant and equipment, net		541,802			520,638

OTHER ASSETS:
Advance royalties		21,692			25,974
Other long-term assets		16,626			18,137

Total other assets		38,318			44,111

TOTAL ASSETS	$	742,744		$	701,723

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	59,901		$	46,392
Due to affiliates		115			1,343
Accrued taxes other than income taxes		12,481			11,091
Accrued payroll and related expenses		17,375			15,180
Accrued interest		1,216			3,826
Workers’ compensation and pneumoconiosis benefits		8,120			8,124
Current capital lease obligation		371			377
Other current liabilities		8,309			6,754
Current maturities, long-term debt		18,000			18,000

Total current liabilities		125,888			111,087

LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities		158,000			136,000
Pneumoconiosis benefits		29,936			29,392
Workers’ compensation		45,591			44,150
Asset retirement obligations		54,681			54,903
Due to affiliates		1,329			1,295
Long-term capital lease obligation		1,049			1,135
Minority interest		648			507
Other liabilities		5,994			6,037

Total long-term liabilities		297,228			273,419

Total liabilities		423,116			384,506

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:
Limited Partners - Common Unitholders 36,613,458 and 36,550,659 units outstanding, respectively		619,675			607,777
General Partners’ deficit		(300,156	)		(290,669	)
Accumulated other comprehensive income		109			109

Total Partners’ capital		319,628			317,217

TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	742,744		$	701,723

See notes to condensed consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except unit and per unit data)

(Unaudited)


	Three Months Ended March 31,
	2008			2007
SALES AND OPERATING REVENUES:
Coal sales	$	269,158		$	238,870
Transportation revenues		10,620			8,679
Other sales and operating revenues		3,810			9,522

Total revenues		283,588			257,071

EXPENSES:
Operating expenses (excluding depreciation, depletion and amortization)		192,618			166,989
Transportation expenses		10,620			8,679
Outside purchases		2,903			6,266
General and administrative		8,831			7,929
Depreciation, depletion and amortization		23,294			19,793

Total operating expenses		238,266			209,656

INCOME FROM OPERATIONS		45,322			47,415
Interest expense (net of interest capitalized for the three months ended March 31, 2008 and 2007 of $222 and $316, respectively)		(2,988	)		(2,818	)
Interest income		98			534
Other income		217			901

INCOME BEFORE INCOME TAXES AND MINORITY INTEREST		42,649			46,032
INCOME TAX EXPENSE (BENEFIT)		(655	)		574

INCOME BEFORE MINORITY INTEREST		43,304			45,458
MINORITY INTEREST (EXPENSE)		(141	)		82

NET INCOME	$	43,163		$	45,540

GENERAL PARTNERS’ INTEREST IN NET INCOME	$	9,156		$	7,611

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	34,007		$	37,929

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.76		$	0.79

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.76		$	0.79

DISTRIBUTIONS PAID PER COMMON UNIT	$	0.585		$	0.54

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-BASIC		36,578,263			36,540,485

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-DILUTED		36,753,837			36,765,573

See notes to condensed consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2008			2007
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	66,426		$	69,005

CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(34,049	)		(30,725	)
Changes in accounts payable and accrued liabilities		3,467			(5,803	)
Proceeds from sale of property, plant and equipment		7			53
Proceeds from marketable securities		—			260
Payment for acquisition of coal reserves and other assets		(13,300	)		—
Advances on Gibson rail project		—			(1,754	)
Receipts of prior advances on Gibson rail project		738			—

Net cash used in investing activities		(43,137	)		(37,969	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facilities		76,100			—
Payments under revolving credit facilities		(54,100	)		—
Payments on capital lease obligation		(92	)		(60	)
Cash contribution by General Partners		50			91
Distributions paid to Partners		(30,469	)		(27,064	)

Net cash used in financing activities		(8,511	)		(27,033	)

NET CHANGE IN CASH AND CASH EQUIVALENTS		14,778			4,003
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		1,118			36,789

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	15,896		$	40,792

SUPPLEMENTAL CASH FLOW INFORMATION:
CASH PAID FOR:
Interest	$	5,745		$	6,042

Income taxes	$	—		$	650

NON-CASH INVESTING ACTIVITY:
Purchase of property, plant and equipment	$	8,512		$	6,337

See notes to condensed consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.	ORGANIZATION AND PRESENTATION

Significant relationships referenced in Notes to Condensed Consolidated Financial Statements

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

Organization

ARLP is a Delaware limited partnership listed on the NASDAQ Global Select Market under the ticker symbol “ARLP.” ARLP was formed in May 1999 to acquire, upon completion of ARLP’s initial public offering on August 19, 1999, certain coal production and marketing assets of Alliance Resource Holdings, Inc., a Delaware corporation (“ARH”), consisting of substantially all of ARH’s operating subsidiaries, but excluding ARH. ARH was previously owned by our current and former management. In June 2006, our special general partner, SGP, and its parent, ARH, became wholly-owned, directly and indirectly, by Joseph W. Craft, III, 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 March 31, 2008 and December 31, 2007, and results of our operations and cash flows for the three months ended March 31, 2008 and 2007. All material intercompany transactions and accounts of the ARLP Partnership have been eliminated.

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

These condensed consolidated financial statements and notes are prepared pursuant to the rules and regulations of the Securities and Exchange Commission for interim reporting and should be read in conjunction with the consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 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 determined that this transaction reflected market-clearing terms and conditions customary in the coal industry and approved the transaction as fair and reasonable to us and our limited partners.

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 intend to mine 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.

5.	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.

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 months ended March 31, 2008 (in thousands):


	Balance December 31, 2007		Accruals	Payments		Interest Accretion	Valuation Changes (Gain)/Loss		Balance March 31, 2008
Workers’ compensation liability	$	51,619	4,181	(2,824	)	765	(685	)	$	53,056
Long-term disability liability		2,791	—	(61	)	46	—			2,776

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 March 31, 2008 and December 31, 2007, respectively, the estimated fair value of our senior notes was $136.1 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.

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.

6.	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 was effective for fiscal periods beginning after March 31, 2004. 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 March 31,
	2008			2007
Net income	$	43,163		$	45,540
Adjustments:
General partner’s priority distributions		(8,462	)		(6,837	)
General partners’ 2% equity ownership		(694	)		(774	)

Limited partners’ interest in net income		34,007			37,929
Additional earnings allocation to general partners		(6,165	)		(8,910	)

Net income available to limited partners under EITF No. 03-6	$	27,842		$	29,019

Weighted average limited partner units – basic		36,578			36,540

Basic net income per limited partner unit	$	0.76		$	0.79

Weighted average limited partner units – basic		36,578			36,540
Units contingently issuable:
Restricted units for Long-Term Incentive Plan		137			97
Directors’ compensation units		12			33
Supplemental Executive Retirement Plan		27			96

Weighted average limited partner units, assuming dilutive effect of restricted units		36,754			36,766

Diluted net income per limited partner unit	$	0.76		$	0.79

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. The Partnership is evaluating the requirements of EITF 07-4 and the impact on our net income per limited partner unit calculations (Note 9).

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.

7.	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 nonvested 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 March 31, 2008, 122,661 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 $0.7 million, for the three months ended March 31, 2008 and 2007, respectively.

As of March 31, 2008, there was $5.4 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 1.8 years. As of March 31, 2008, the intrinsic value of the non-vested LTIP grants was $9.0 million. As of March 31, 2008, the total obligation associated with the LTIP was $3.2 million and is included in the partners’ capital-limited partners line item in our condensed consolidated balance sheets.

8.	COMPONENTS OF PENSION PLAN NET PERIODIC BENEFIT COSTS

Employees at certain of our mining operations participate in a defined benefit plan (the “Pension Plan”) that we sponsor. Employees hired for pay periods beginning after July 1, 2008 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. Employees participating in the Pension Plan prior to the first pay period ending after July 1, 2008 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 March 31,
	2008			2007
Service cost	$	703		$	859
Interest cost		653			567
Expected return on plan assets		(880	)		(672	)
Amortization of actuarial loss		—			64

Net periodic benefit cost	$	476		$	818

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 March 31, 2008, we had made no contributions to the Pension Plan in 2008.

9.	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 5).

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 5).

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 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 are currently evaluating the requirements of EITF No. 07-4, to determine the impact, if any, on our consolidated financial statements.

10.

COMPREHENSIVE INCOME

For the three months ended March 31, 2008 and 2007, respectively, we had no items that affected comprehensive income. Accordingly, net income and comprehensive income are the same.

11.

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 Coal, LLC’s (“River View”) property and 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”) and Matrix Design Group, LLC (“Matrix Design”). Operating segment results for the three months ended March 31, 2008 and 2007 are presented below:


	Illinois Basin		Central Appalachia		Northern Appalachia		Other and Corporate			Elimination (1)			Consolidated
	(in thousands)
Operating segment results for the three months ended March 31, 2008:

Total revenues (2)	$	191,913	$	49,333	$	40,312	$	3,945		$	(1,915	)	$	283,588
Segment Adjusted EBITDA Expense (3)		127,026		38,149		28,193		3,972			(2,036	)		195,304
Segment Adjusted EBITDA (4)		57,450		11,122		8,998		(26	)		120			77,664
Total assets		479,988		100,351		131,750		30,760			(105	)		742,744
Capital expenditures (5)		29,203		2,050		2,469		327			—			34,049

Operating segment results for the three months ended March 31, 2007:

Total revenues (2)	$	167,873	$	43,503	$	38,780	$	8,194			(1,279	)	$	257,071
Segment Adjusted EBITDA Expense (3)		106,386		32,721		26,668		7,858			(1,279	)		172,354
Segment Adjusted EBITDA (4)		56,496		10,347		8,860		335			—			76,038
Total assets		366,693		102,720		125,492		62,585			—			657,490
Capital expenditures		22,583		3,149		4,325		668			—			30,725

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

(2)

Revenues included in the Other and Corporate column are attributable to Mt. Vernon transloading revenues, Matrix Design revenues. MAC rock dust revenues for the three months ended March 31, 2008 and brokerage sales, Mt. Vernon transloading revenues and Matrix Design revenues for the three months ended March 31, 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 margin on transportation revenues.

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


	Three Months Ended March 31,
	2008			2007
Segment Adjusted EBITDA Expense	$	195,304		$	172,354
Outside purchases		(2,903	)		(6,266	)
Other income		217			901

Operating expenses (excluding depreciation, depletion and amortization)	$	192,618		$	166,989

(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 March 31,
	2008			2007
Segment Adjusted EBITDA	$	77,664		$	76,038
General and administrative		(8,831	)		(7,929	)
Depreciation, depletion and amortization		(23,294	)		(19,793	)
Interest expense, net		(2,890	)		(2,284	)
Income tax (expense) benefit		655			(574	)
Minority interest (expense)		(141	)		82

Net income	$	43,163		$	45,540

(5)	Capital expenditures 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.

12.

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 $0.6 million and $0.8 million as of March 31, 2008 and 2007, respectively, which is recorded as minority interest on our condensed consolidated balance sheet.

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.

13.

SUBSEQUENT EVENTS

On April 28, 2008, we declared a quarterly distribution for the quarter ended March 31, 2008, of $0.585 per unit, totaling approximately $30.3 million (which includes our managing general partner’s incentive distributions), on all common units outstanding, payable on May 15, 2008 to all unitholders of record as of May 8, 2008.

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 “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 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 Excel No. 3 mine.

•

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”).

Expiration of Federal Non-Conventional Source Fuel Tax Credit

Historically, we have 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 our coal to the synfuel operators rather we sell directly to Louisville Gas and Electric Company, Seminole Electric Cooperative, Inc, Tennessee Valley Authority and Virginia Electric and Power Company, which individually accounted for 10% or more of our total revenues for the quarter ended March 31, 2008 (“2008 Quarter”), among other customers. We realized benefits for the quarter ended March 31, 2007 (“2007 Quarter”) of approximately $8.1 million in net income from various coal synfuel-related agreements.

Results of Operations

Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007

We reported net income of $43.2 million for the 2008 Quarter compared to $45.5 million for the 2007 Quarter. This decrease of $2.3 million principally due to the loss of synfuel-related benefits and higher depreciation, depletion and amortization resulting from capital expenditures associated with ARLP’s growth initiatives, partially offset by improved coal sales and related operating profits. We had record tons sold of 7.0 million and tons produced of 6.9 million for the 2008 Quarter compared to 6.2 million tons sold and 6.6 million tons produced for the 2007 Quarter. Increased operating expenses during the 2008 Quarter primarily reflect the increase in record tons produced, increased sales related expenses due to record tons sold as well as higher regulatory compliance costs and other factors described below.


	March 31,				March 31,
	2008		2007		2008		2007
	(in thousands)				(per ton sold)
Tons sold		6,994		6,178		N/A		N/A
Tons produced		6,865		6,557		N/A		N/A
Coal sales	$	269,158	$	238,870	$	38.48	$	38.66
Operating expenses and outside purchases	$	195,521	$	173,255	$	27.96	$	28.04

Coal sales. Coal sales for the 2008 Quarter increased 12.7% to $269.2 million from $238.9 million for the 2007 Quarter. The increase of $30.3 million reflected record tons sold of 7.0 million (contributing $31.6 million of the increase) for the 2008 Quarter compared to 6.2 million for the 2007 Quarter, partially offset by lower average coal sales prices (offsetting $1.3 million of the increase). Record tons produced increased 4.7% to 6.9 million tons for the 2008 Quarter from 6.6 million tons for the 2007 Quarter.

Operating expenses. Operating expenses increased 15.3% to $192.6 million for the 2008 Quarter from $167.0 million for the 2007 Quarter. The increase of $25.6 million resulted from the impact of the following specific factors:

•

Higher operating expenses associated with an additional 954,000 produced tons sold;

•

Labor and benefit expenses per ton produced decreased to $9.38 per ton in the 2008 Quarter from $9.44 per ton in the 2007 Quarter reflecting decreased workers’ compensation costs partially offset by increased headcount due to capacity expansion, pay rate increases and increased health care costs;

•

Material and supplies, and maintenance expenses per ton produced increased 9.3% and 3.1%, respectively, to $9.07 and $2.98 per ton, respectively, in the 2008 Quarter from $8.30 and $2.89 per ton produced respectively in the 2007 Quarter. The respective increases of $0.77 and $0.09 per ton produced resulted from increased costs for certain products and services (particularly roof support and seals) 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 $1.7 million as a result of increased tons sold; and

•

Reduced expenses of $5.3 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.

General and administrative. General and administrative expenses for the 2008 Quarter increased to $8.8 million compared to $7.9 million in the 2007 Quarter. The increase was primarily due to higher salary and benefit costs related to increased staffing levels and higher incentive compensation expense.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, outside services and administrative services revenue from affiliates and, for the 2007 Quarter only, rental and service fees from third-party coal synfuel facilities. Other sales and operating revenues decreased to $3.8 million for the 2008 Quarter from $9.5 million for the 2007 Quarter. The decrease of $5.7 million is primarily attributable to the loss of synfuel-related benefits due to the expiration on December 31, 2007 of the non-conventional synfuel tax credits, partially offset by increased revenues from hoist and control system services, mine safety services and products and revenue from outside services. A more detailed discussion of our synfuel-related arrangements is discussed above under “–Summary.”

Outside purchases. Outside purchases decreased to $2.9 million for the 2008 Quarter from $6.3 million in the 2007 Quarter. The decrease of $3.4 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 new coal market opportunities.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $23.3 million for the 2008 Quarter from $19.8 million for the 2007 Quarter. The increase of $3.5 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, was comparable for the 2008 and 2007 Quarters at $3.0 million and $2.8 million, respectively.

Interest income. Interest income decreased to $0.1 million for the 2008 Quarter from $0.5 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 10.6 million for the 2008 Quarter compared to $8.7 million for the 2007 Quarter. The increase of $1.9 million was primarily attributable to higher transported coal volumes of 2.3 million tons in the 2008 Quarter compared to 1.9 million tons in the 2007 Quarter. The cost of transportation services are passed through to our customers. Consequently, we do not realize any margin on transportation revenues.

Income before income taxes and minority interest. Income before income taxes and minority interest for the 2008 and 2007 Quarters was $42.6 million and $46.0 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 $0.7 million compared to income tax expense of $0.6 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 supplied to a third-party coal synfuel facility, which ceased operations on December 31, 2007 with the expiration of the synfuel tax credits A more detailed discussion of our synfuel-related arrangements is discussed 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 $141,000 for the 2008 Quarter and a net loss of $82,000 for the 2007 Quarter and is recorded as minority interest on our condensed consolidated income statement.

Segment Adjusted EBITDA. Our 2008 Quarter Segment Adjusted EBITDA increased $1.6 million, or 2.1%, to $77.7 million from 2007 Quarter Segment Adjusted EBITDA of $76.0 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 March 31,						Increase/(Decrease)
	2008			2007			Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	57,450		$	56,496		$	954		1.7	%
Central Appalachia		11,122			10,347			775		7.5	%
Northern Appalachia		8,998			8,860			138		1.6	%
Other and Corporate		(26	)		335			(361	)	(3	)
Elimination		120			—			120		—

Total Segment Adjusted EBITDA (1)	$	77,664		$	76,038		$	1,626		2.1	%

Tons sold
Illinois Basin		5,365			4,528			837		18.5	%
Central Appalachia		845			838			7		0.8	%
Northern Appalachia		784			812			(28	)	(3.4	)%
Other and Corporate		—			—			—		—
Elimination		—			—			—		—

Total tons sold		6,994			6,178			816		13.2	%

Coal sales
Illinois Basin	$	183,903		$	155,192		$	28,711		18.5	%
Central Appalachia		49,110			42,995			6,115		14.2	%
Northern Appalachia		36,145			34,524			1,621		4.7	%
Other and Corporate		—			6,159			(6,159	)	(3	)
Elimination		—			—			—		—

Total coal sales	$	269,158		$	238,870		$	30,288		12.7	%

Other sales and operating revenues
Illinois Basin	$	573		$	7,690		$	(7,117	)	(92.5	)%
Central Appalachia		161			72			89		(3	)
Northern Appalachia		1,046			1,004			42		4.2	%
Other and Corporate		3,945			2,035			1,910		93.9	%
Elimination		(1,915	)		(1,279	)		(636	)	(49.7	)%

Total other sales and operating revenues	$	3,810		$	9,522		$	(5,712	)	(60.0	)%

Segment Adjusted EBITDA Expense
Illinois Basin	$	127,026		$	106,386		$	20,640		19.4	%
Central Appalachia		38,149			32,721			5,428		16.6	%
Northern Appalachia		28,193			26,668			1,525		5.7	%
Other and Corporate		3,972			7,858			(3,886	)	(49.5	)%
Elimination		(2,036	)		(1,279	)		(757	)	(59.2	)%

Total Segment Adjusted EBITDA Expense (2)	$	195,304		$	172,354		$	22,950		13.3	%

(1)	Segment Adjusted EBITDA is defined as EBITDA as described below, 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 March 31,
	2008			2007
Segment Adjusted EBITDA	$	77,664		$	76,038

General and administrative		(8,831	)		(7,929	)
Depreciation, depletion and amortization		(23,294	)		(19,793	)
Interest expense, net		(2,890	)		(2,284	)
Income tax (expense) benefit		655			(574	)
Minority interest (expense)		(141	)		82

Net income	$	43,163		$	45,540

(2)

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 margin 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.

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


	Three Months Ended March 31,
	2008			2007
Segment Adjusted EBITDA Expense	$	195,304		$	172,354

Outside purchases		(2,903	)		(6,266	)
Other income		217			901

Operating expense	$	192,618		$	166,989

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

Illinois Basin – Segment Adjusted EBITDA for the 2008 and 2007 Quarters, as defined in reference (1) to the table above, increased 1.7% or $1.0 million to $57.5 million in the 2008 Quarter, from $56.5 million in the 2007 Quarter. This increase is primarily the result of an 18.5% increase in coal sales which increased $28.7 million to $183.9 million in the 2008 Quarter, as compared to $155.2 million in the 2007 Quarter and an increase of 0.9 million tons sold to 5.4 million in the 2008 Quarter compared to 4.5 million tons in the 2007 Quarter, which was primarily driven by increased production, most significantly from the Elk Creek mine. Other sales and operating revenues decreased $7.1 million, primarily due to the expiration on December 31, 2007 of the non-conventional synfuel-related tax credits and the concurrent loss of benefits derived from supplying third-party coal synfuel facilities with coal feedstock and related services. A more detailed discussion of our synfuel-related arrangements is discussed above under “–Summary.” Segment Adjusted EBITDA Expense, as defined in reference (2) to the above table, for the 2008 Quarter increased 19.4% to $127.0 million from $106.4 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.

Central Appalachia – Segment Adjusted EBITDA for the 2008 Quarter, as defined in reference (1) to the table above, increased $0.8 million to $11.1 million compared to the 2007 Quarter Segment Adjusted EBITDA of $10.3 million. Due to improved contract pricing and increased sales into a higher priced spot market, average coal sales price increased 13.3% to $58.08 per ton in the 2008 Quarter, as compared to $51.28 per ton in the 2007 Quarter. Segment Adjusted EBITDA Expense, as defined in reference (2) to the above table, for the 2008 Quarter increased 16.6% to $38.1 million from $32.7 million in the 2007 Quarter. The average Segment Adjusted EBITDA Expense per ton sold during the 2008 Quarter was $45.12, an increase of $6.09 per ton, or 15.6%, as compared to $39.03 per ton in the 2007 Quarter. The increase in 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, partially offset by certain favorable operating tax adjustments.

Northern Appalachia – Segment Adjusted EBITDA for the 2008 Quarter, as defined in reference (1) to the table above, increased 1.6%, to $9.0 million as compared to the 2007 Quarter Segment Adjusted EBITDA of $8.9 million. The increase was primarily attributable to higher average coal sales prices in Northern Appalachia of $46.12 per ton during the 2008 Quarter as compared to $42.54 per ton during the 2007 Quarter, which are primarily due to 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 $35.98, an increase of $3.12 per ton, or 9.5%, as compared to $32.86 per ton in the 2007 Quarter (for a definition of Segment Adjusted EBITDA Expense, see reference (2) to the above table). The increase in Segment Adjusted EBITDA Expense per ton sold was primarily a result of higher tons produced in the 2007 Quarter reflecting accelerated continuous miner production associated with transition to the Mountain View mine, a non-recurring gain on the sale of equipment in the 2007 Quarter and higher purchased coal expense per ton in the 2008 Quarter, partially offset by lower maintenance costs per ton in the 2008 Quarter.

Other and Corporate – The decrease in Segment Adjusted EBITDA Expense as defined in reference (2) 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 terminated ICG agreement referred to above under consolidated operating expenses, partially offset by increased expenses associated with higher outside services revenue.

Liquidity and Capital Resources

Cash Flows

Cash provided by operating activities was $66.4 million for the 2008 Quarter compared to $69.0 million for the 2007 Quarter. The decrease in cash provided by operating activities was primarily attributable to a decrease in net income.

Net cash used in investing activities was $43.1 million for the 2008 Quarter compared to $38.0 million for the 2007 Quarter. The increased use of cash in the 2008 Quarter was primarily attributable to our subsidiary Alliance Resource Properties’ acquisition of additional rights to approximately 48.2 million tons of coal reserves located in western Kentucky from SGP Land, LLC (“SGP Land”). See Note 3. Acquisitions to the Unaudited Condensed Consolidated Financial Statements included in “Item 1. Financial Statement (Unaudited)” of this Quarterly Report on Form 10-Q. Additionally, there were timing differences in accounts payable and accrued liabilities related to capital expenditures, partially offset by an increase in capital expenditures. The increase in capital expenditures in the 2008 Quarter (excluding the Alliance Resource Properties’ acquisition) was primarily attributable to the addition of a continuous mining unit at our Elk Creek mine.

Net cash used in financing activities was $8.5 million for the 2008 Quarter compared to $27.0 million for the 2007 Quarter. The reduced use of cash primarily was attributable to net borrowings under our revolving credit facility of $22.0 million in the 2008 Quarter used to finance the Alliance Resource Properties’ acquisition, partially offset by an increase in distributions paid to partners in the 2008 Quarter.

Capital Expenditures

Capital expenditures increased to $34.0 million in the 2008 Quarter from $30.7 million in the 2007 Quarter. See discussion of “Cash Flows” above concerning the increase in capital expenditures.

Including newly authorized capital development for our River View mine, our anticipated total capital expenditures for 2008 are estimated to be in a range of $200.0 to $220.0 million. We will continue to have significant capital requirements over the long-term, which may require us to incur debt or seek additional equity capital. The availability of additional capital will depend upon prevailing market conditions, the market price of our common units and several other factors over which we have limited control, as well as our financial condition and results of operations. Based on our recent operating results, current cash position, anticipated future cash flows, and sources of financing that we expect will be available to us, we do not expect that we will experience any significant liquidity constraints in the foreseeable future.

Debt Obligations

Senior Notes and Credit Facility

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”). On September 25, 2007, our Intermediate Partnership entered into a $150.0 million revolving credit facility (“ARLP Credit Facility”), which matures in 2012. The ARLP Credit Facility amended a $100.0 million credit facility that would have matured in 2011. 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 March 31, 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 3.64%. 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 March 31, 2008, we had $50.0 million of borrowings and $24.6 million of letters of credit outstanding with $75.4 million available for borrowing under the ARLP Credit Facility.

The Senior Notes and ARLP Credit Facility are guaranteed by all of the subsidiaries of our Intermediate Partnership. The Senior Notes and ARLP Credit Facility 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 Senior Notes and the ARLP Credit Facility also require the Intermediate Partnership to remain in control of a certain amount of mineable coal relative to its annual production. In addition, the Senior Notes and the ARLP Credit Facility require the 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 both the ARLP Credit Facility and Senior Notes at March 31, 2008.

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 March 31, 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”) 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.

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We have long-term coal supply agreements. Virtually all of our long-term coal supply agreements 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 March 31, 2008, the estimated fair value of the Senior Notes was approximately $136.1 million. The fair values of long-term debt are estimated using discounted cash flow analyses, based upon our current incremental borrowing rates for similar types of borrowing arrangements as of March 31, 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.

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 March 31, 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 March 31, 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.

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 and 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.”

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.

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


3.1		Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P., dated April 14, 2008 (incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed with the Commission on April 18, 2008, File No. 000-26823).

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 May 12, 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 May 12, 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 May 12, 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 May 12, 2008, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Filed herewith.

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 May 12, 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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