Alliance Resource Partners (ARLP) 10-Q 2005 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2005

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 600, Tulsa, Oklahoma 74119

(Address of principal executive offices and zip code)

(918) 295-7600

(Registrant’s telephone number, including area code)

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

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

As of May 9, 2005, 18,130,440 Common Units are outstanding.

TABLE OF CONTENTS

		Page
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)
	ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
	Condensed Consolidated Balance Sheets as of March 31, 2005 and December 31, 2004	1
	Condensed Consolidated Statements of Income for the three months ended March 31, 2005 and 2004	2
	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2005 and 2004	3
	Notes to Condensed Consolidated Financial Statements	4
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	13
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	19
ITEM 4.	CONTROLS AND PROCEDURES	20
	FORWARD-LOOKING STATEMENTS	21
	PART II
	OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	23
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	23
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	23
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	23
ITEM 5.	OTHER INFORMATION	23
ITEM 6.	EXHIBITS	23

PART 1

FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

	March 31, 2005			December 31, 2004
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	28,157		$	31,177
Trade receivables, net		75,577			56,967
Other receivables		11,659			1,637
Marketable securities		49,312			49,397
Inventories		18,645			13,839
Advance royalties		3,117			3,117
Prepaid expenses and other assets		3,180			4,345
Total current assets		189,647			160,479
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment at cost		538,275			526,468
Less accumulated depreciation, depletion and amortization		(300,622	)		(292,900	)
Total property, plant and equipment		237,653			233,568
OTHER ASSETS:
Advance royalties		14,040			11,737
Coal supply agreements, net		2,042			2,723
Other long-term assets		4,017			4,277
Total other assets		20,099			18,737
TOTAL ASSETS	$	447,399		$	412,784
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	40,790		$	30,961
Due to affiliates		9,386			10,338
Accrued taxes other than income taxes		12,605			10,742
Accrued payroll and related expenses		14,353			11,730
Accrued interest		1,662			5,402
Workers’ compensation and pneumoconiosis benefits		7,085			7,081
Other current liabilities		9,949			12,051
Current maturities, long-term debt		18,000			18,000
Total current liabilities		113,830			106,305
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities		162,000			162,000
Accrued pneumoconiosis benefits		20,657			19,833
Workers’ compensation		27,121			25,994
Reclamation and mine closing		33,680			32,838
Due to affiliates		7,505			7,457
Other liabilities		3,228			3,170
Total long-term liabilities		254,191			251,292
Total liabilities		368,021			357,597
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
Common Unitholders 18,130,440 units outstanding		387,454			363,658
General Partners’ deficit		(302,809	)		(303,295	)
Unrealized loss on marketable securities		(145	)		(54	)
Minimum pension liability		(5,122	)		(5,122	)
Total Partners’ capital		79,378			55,187
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	447,399		$	412,784

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except unit and per unit data)

(Unaudited)

	Three Months Ended March 31,
	2005		2004
SALES AND OPERATING REVENUES:
Coal sales	$	178,846	$	144,539
Transportation revenues		9,623		6,838
Other sales and operating revenues		7,158		6,447
Total revenues		195,627		157,824
EXPENSES:
Operating expenses		119,393		104,328
Transportation expenses		9,623		6,838
Outside purchases		4,117		1,065
General and administrative		5,708		10,329
Depreciation, depletion and amortization		13,628		12,771
Interest expense (net of interest income and interest capitalized for the three months ended March 31, 2005 and 2004 of $472 and $110, respectively)		3,474		3,843
Total operating expenses		155,943		139,174
INCOME FROM OPERATIONS		39,684		18,650
OTHER INCOME		105		314
INCOME BEFORE INCOME TAXES		39,789		18,964
INCOME TAX EXPENSE		710		739
NET INCOME	$	39,079	$	18,225
GENERAL PARTNERS’ INTEREST IN NET INCOME	$	1,685	$	365
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	37,394	$	17,860
BASIC NET INCOME PER LIMITED PARTNER UNIT	$	2.06	$	1.00
DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	2.02	$	0.97
DISTRIBUTION PAID PER COMMON AND SUBORDINATED UNIT	$	0.75	$	0.5625
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-BASIC		18,130,440		17,903,793
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-DILUTED		18,496,414		18,439,099

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2005			2004
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	28,504		$	34,533
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property, plant and equipment		(16,914	)		(13,427	)
Proceeds from sale of property, plant and equipment		193			254
Purchase of marketable securities		(9,727	)		—
Proceeds from marketable securities		9,721			3,615
Net cash used in investing activities		(16,727	)		(9,558	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to Partners		(14,797	)		(10,312	)
Net cash used in financing activities		(14,797	)		(10,312	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		(3,020	)		14,663
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		31,177			10,156
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	28,157		$	24,819
CASH PAID FOR:
Interest	$	7,546		$	7,546
Income taxes to taxing authorities	$	250		$	—

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND PRESENTATION

Alliance Resource Partners, L.P., a Delaware limited partnership (the “Partnership”), was formed in May 1999, to acquire, own and operate certain coal production and marketing assets of Alliance Resource Holdings, Inc., a Delaware corporation (“ARH”) (formerly known as Alliance Coal Corporation), consisting of substantially all of ARH’s operating subsidiaries, but excluding ARH.

The accompanying condensed consolidated financial statements include the accounts and operations of the Partnership and present the financial position as of March 31, 2005 and December 31, 2004, and the results of its operations and cash flows for the three months ended March 31, 2005 and 2004. All material intercompany transactions and accounts of the Partnership have been eliminated.

These condensed consolidated financial statements and notes thereto for interim periods 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 of 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 the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2004.

2. CONTINGENCIES

The Partnership is involved in various lawsuits, claims and regulatory proceedings incidental to its business. The Partnership provides for costs related to litigation and regulatory proceedings, including civil fines issued as part of the outcome of these proceedings, when a loss is probable and the amount is reasonably determinable. Although the ultimate outcome of these matters cannot be predicted with certainty, in the opinion of management, the outcome of these matters, to the extent not previously provided for or covered under insurance, are not expected to have a material adverse effect on the Partnership’s business, financial position or results of operations. Nonetheless, these matters or estimates that are based on current facts and circumstances, if resolved in a manner different from the basis on which management has formed its opinion, could have a material adverse effect on the Partnership’s financial position or results of operations.

Mettiki Coal (WV), LLC has proposed a long-wall underground mine (the “E-Mine”) to be located primarily in Tucker County, West Virginia, which will eventually replace coal production at the Partnership’s Mettiki Coal, LLC’s existing long-wall mine (the “D-Mine”), located in Garrett County, Maryland. The proposed mine, which will be either a long-wall or continuous mining operation, is approximately 10 miles from Mettiki Coal. In order to proceed with the development of the E-Mine, Mettiki Coal (WV) filed two separate permit applications with the West Virginia Department of Environmental Protection (“WVDEP”) concerning on-site disposal of scalp rock and underground mining, each requiring an associated water discharge permit. The Partnership was notified on April 16, May 13, May 26, and June 7, 2004, that WVDEP had issued the permits for on-site disposal of scalp rock, underground mining, water discharge related to the operation of the scalp rock disposal facility, and water discharge related to the operation of the underground mine, respectively.

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The appeal periods for the scalp rock permit and the two water discharge permits related to the operation of the scalp rock disposal facility and underground mine lapsed without any appeal being filed. Two appeals of the underground mining permit were filed on June 11 and 16, 2004, respectively. The West Virginia Surface Mine Board (“SMB”) consolidated the two appeals and held administrative hearings on October 19 and 20, 2004, December 7 and 8, 2004 and January 11 and February 7, 2005.

On March 8, 2005, the SMB issued a final order (the “Final Order”) concluding consideration of the consolidated appeals without a decision. The Final Order held that the SMB was unable to take any action relating to the issuance of the underground permit by WVDEP because its vote did not obtain the concurrence of at least four SMB members as required by West Virginia law. Consequently, the ultimate decision by the WVDEP to issue the underground permit was affirmed by operation of West Virginia law. In the Final Order, however, the SMB voted unanimously to require Mettiki Coal (WV) to increase the amount of a surety bond that serves as security for a portion of the reclamation plan approved by WVDEP as part of the underground permit.

Also, on March 8, 2005, Mettiki Coal (WV) filed an appeal of the Final Order with the Circuit Court of Tucker County, West Virginia (the “Tucker County Court”), on the ground that the SMB was wrong in ordering Mettiki Coal (WV) to increase the surety bond for part of the reclamation plan approved by WVDEP when the SMB, as a result of not obtaining the concurrence of at least four members, failed to affirm the decision by WVDEP to issue a final order approving the underground permit issued by WVDEP on May 13, 2004.

On March 10, 2005 the West Virginia Rivers Coalition, the West Virginia Highlands Conservancy, and Trout Unlimited – West Virginia Council (collectively, the “Appellants”) filed an appeal of the Final Order with the Circuit Court of Kanawha County, West Virginia (the “Kanawha County Court”). The appeal requested that the Kanawha County Court (a) grant a stay of the WVDEP’s approval of the E-Mine permit pending a decision by the Kanawha County Court, (b) set a briefing schedule and oral argument of the appeal and (c) reverse and vacate the WVDEP’s approval of the underground permit.

On March 21, 2005, the Tucker County Court ordered the appeal pending before the Kanawha County Court be transferred to the Tucker County Court, the two appeals be consolidated for all subsequent proceedings and directed the SMB to file a certified record of the proceedings before the SMB with the Tucker County Court clerk. This certified record was transmitted to the Tucker County Court on April 8, 2005.

Notwithstanding the consolidated appeals pending before the Tucker County Court, on April 19, 2005, counsel for the Appellants submitted a letter to the U.S Department of Interior’s Office of Surface Mining, Reclamation and Enforcement (“OSM”) requesting the Director of OSM evaluate, consistent with its statutory oversight responsibilities, the State of West Virginia’s program in regard to the issuance of underground permits that will create acid mine drainage with no defined end point, particularly for the E-Mine. As part of their request, the Appellants asked the Director of OSM to initiate a federal monitoring and inspection review of the E-Mine. Under applicable federal regulations, a person may request the Director of OSM to evaluate the administration and enforcement of an approved state program. In those unusual instances when an interested party requests a program review, the Director of OSM evaluates those aspects of the implementation, administration, maintenance or enforcement of the state program identified by the complainant.

OSM issued a ten-day notice, dated April 21, 2005, to WVDEP advising a citizen’s complaint had been received alleging, among other matters, the underground permit for the E-Mine will cause material harm on and off-site of the permit area to the hydrological balance. WVDEP has requested an extension of time in which to respond and its response is due on or before June 8, 2005. We expect

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OSM will complete an evaluation of the citizen’s complaint and WVDEP ‘s response to the ten-day notice, and issue a determination on WVDEP’s approved state program on or before the end of June 2005. Management believes the WVDEP’s approval of the underground permit application will be ultimately upheld.

After the consolidation of the appeals before the Tucker County Court and subsequent to the request made by Appellants to the Director of OSM, the Appellants and Mettiki Coal (WV) voluntarily agreed to withdraw their respective appeals and moved the Tucker County Court to dismiss these appeals with prejudice. On April 26, 2005, the Tucker County Court granted the motion to dismiss and entered an order dismissing both appeals with prejudice.

On October 12, 2004, Pontiki Coal, LLC (“Pontiki”), one of the Partnership’s subsidiaries and the successor-in-interest of Pontiki Coal Corporation as a result of a merger completed on August 4, 1999, was served with a complaint from ICG, LLC (“ICG”) alleging a breach of contract and seeking declaratory relief to determine the parties’ rights under a coal sales agreement between Horizon Natural Resource Sales Company (“Horizon Sales”), as buyer, and Pontiki Coal Corporation, as seller, dated October 3, 1998, as amended on February 28, 2001 (the “Horizon Agreement”). ICG has represented that it acquired the rights and assumed the liabilities of the Horizon Agreement effective September 30, 2004, as part of an asset sale approved by the U.S. Bankruptcy Court supervising the bankruptcy proceedings of Horizon Sales and its affiliates.

The complaint alleges that from January 2004 to August 2004, Pontiki failed to deliver a total of 138,111 tons of coal resulting in an alleged loss of profits for ICG of $4.1 million. The Partnership has been unable to confirm ICG’s calculation of the alleged shortfall of coal deliveries. The Partnership is aware that certain deliveries under the Horizon Agreement were not made during 2004 for reasons including, but not limited to, force majeure events at Pontiki and ICG’s failure to provide transportation services for the delivery of coal as required under the Horizon Agreement. This litigation is in the preliminary stage and, although Pontiki and ICG have had several discussions concerning the potential settlement of this litigation matter, the Partnership does not believe that it is probable that a loss has been incurred. The Partnership also does not believe that this litigation has merit and intends to contest the litigation vigorously. The Partnership is unable, however, to predict the outcome of the litigation or reasonably estimate a range of possible loss given the current status of the litigation.

At certain of the Partnership’s operations, property tax assessments for several years are under audit by various state tax authorities. The Partnership believes that it has recorded adequate liabilities based on reasonable estimates of any property tax assessments that may be ultimately assessed as a result of these audits.

3. TUNNEL RIDGE ACQUISITION

In January 2005, the Partnership acquired 100% of the limited liability company member interests of Tunnel Ridge, LLC for approximately $500,000 and the assumption of reclamation liabilities from ARH, a company owned by management of the Partnership. Tunnel Ridge controls through a coal lease agreement with Alliance Resource GP, LLC (the “Special GP”) an estimated 70 million tons of high-sulfur coal in the Pittsburgh No. 8 coal seam. The Tunnel Ridge reserve area encompasses approximately 50,571 acres of land located in Ohio County, West Virginia and Washington County, Pennsylvania. Under the terms of the coal lease, beginning on January 1, 2005, Tunnel Ridge has paid and will continue to pay the Special GP an advance minimum royalty of $3.0 million per year. The advance royalty payments are fully recoupable against earned royalties.

The acquisition was reviewed by the Board of Directors of Alliance Resource Management GP, LLC (the “Managing GP”), the managing general partner of the Partnership, and its Conflicts Committee.

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Based upon their reviews, it was determined that this transaction reflected market-clearing terms and conditions. As a result, the Board of Directors of the Partnership’s Managing GP and its Conflicts Committee approved the Tunnel Ridge acquisition as fair and reasonable for the Partnership and its limited partners.

4. MINE FIRE INCIDENTS

MC Mining Mine Fire

On December 26, 2004, MC Mining, LLC’s (“MC Mining”) Excel No. 3 mine was temporarily idled following the occurrence of a mine fire (the “MC Mining Fire Incident”). The fire was discovered by mine personnel near the bottom of the Excel No. 3 mine slope late in the evening of December 25, 2004.

Under a firefighting plan developed by MC Mining, in cooperation with mine emergency response teams from the U.S. Department of Labor’s Mine Safety and Health Administration (“MSHA”) and Kentucky Office of Mine Safety and Licensing, the four portals at the Excel No. 3 mine were temporarily capped to deprive the fire of oxygen. A series of boreholes was then drilled into the mine from the surface, and nitrogen gas and foam were injected through the boreholes into the fire area to further suppress the fire. As a result of these efforts, the mine atmosphere was rendered substantially inert, or without oxygen, and the Excel No. 3 mine fire was effectively suppressed. MC Mining then began construction of temporary and permanent barriers designed to completely isolate the mine fire area. Once the construction of the permanent barriers was completed, MC Mining began efforts to repair and rehabilitate the Excel No. 3 mine infrastructure. On February 21, 2005, the repair and rehabilitation efforts had progressed sufficiently to allow initial resumption of production. Production is gradually increasing to anticipated levels, but continues to be adversely impacted by inefficiencies attributable to or associated with the MC Mining Fire Incident.

The Partnership maintains commercial property (including business interruption and extra expense) insurance policies with various underwriters, which policies are renewed annually in October and provide for self-retention and various applicable deductibles, including certain monetary and/or time element forms of deductibles (collectively, the “2005 Deductibles”) and 10% co-insurance (“2005 Co-Insurance”). The Partnership believes such insurance coverage will cover a substantial portion of the total cost of the disruption to MC Mining’s operations. However, until the claim is resolved ultimately, through either the claim adjustment process, settlement, or litigation, with the applicable underwriters, the Partnership can make no assurance of the amount or timing of recovery of insurance proceeds.

The Partnership made an initial estimate of certain costs primarily associated with activities relating to the suppression of the fire and the initial resumption of operations. Operating expenses for the 2004 fourth quarter were increased by $4.1 million to reflect an initial estimate of certain minimum costs attributable to the MC Mining Fire Incident that are not reimbursable under the Partnership’s insurance policies due to the application of the 2005 Deductibles and 2005 Co-Insurance.

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On April 6, 2005, the Partnership submitted to a representative of the underwriters a preliminary estimate of the expenses and losses (including business interruption losses) incurred by MC Mining and other affiliates arising from or in connection with the MC Mining Fire Incident (the “MC Mining Insurance Claim”). The accounting for any future payments, if any, made to the Partnership by the underwriters will be subject to the accounting methodology described below. Currently, the Partnership continues to evaluate its potential insurance recoveries under the applicable insurance policies in the following areas:

1. Fire Brigade/Extinguishing/Mine Recovery Expense; Expenses to Reduce Loss; Debris Removal Expenses; Demolition and Increased Cost of Construction; Expediting Expenses; and Extra Expenses incurred as a result of the fire—These expenses and other costs (e.g. professional fees) associated with extinguishing the fire, reducing the overall loss, demolition of certain property and removal of debris, expediting the recovery from the loss, and extra expenses that would not have been incurred by the Partnership but for the MC Mining Fire Incident are being expensed as incurred with related actual and/or estimated insurance recoveries recorded as they are considered to be probable, up to the amount of the actual cost incurred.

2. Damage to MC Mining mine property - The net book value of property destroyed, which is currently estimated at $104,000, was written off in the first quarter of 2005 with a corresponding amount recorded as an estimated insurance recovery, since such recovery is considered probable. Any insurance proceeds from the claims relating to the MC Mining mine property (other than amounts relating to the matters discussed in 1. above) that exceed the net book value of such damaged property are expected to result in a gain. The anticipated gain will be recorded when the MC Mining Insurance Claim is resolved and/or proceeds are received.

3. MC Mining mine business interruption losses - The Partnership has submitted to a representative of the underwriters an initial business interruption loss analysis for the period of December 24, 2004 through March 31, 2005. Expenses associated with business interruption losses are expensed as incurred, and estimated insurance recoveries of such losses are recognized to the extent such recoveries are considered to be probable, up to the actual amount incurred. Recoveries in excess of actual costs incurred will be recorded as gains when the MC Mining Insurance Claim is resolved and/or proceeds are received.

Pursuant to the accounting methodology described above, the Partnership has recorded $9.2 million as an offset to operating expenses during the three months ended March 31, 2005, which amount represents the current estimated insurance recovery of actual costs incurred, net of the 2005 Deductibles and 2005 Co-Insurance. The Partnership continues to discuss the MC Mining Insurance Claim and the determination of the total claim amount with representatives of the underwriters. The MC Mining Insurance Claim will continue to be developed as additional information becomes available and the Partnership has completed its assessment of the losses (including the methodologies associated therewith) arising from or in connection with the MC Mining Fire Incident. At this time, based on the magnitude and complexity of the MC Mining Insurance Claim, the Partnership is unable to reasonably estimate the total amount of the MC Mining Insurance Claim as well as its exposure, if any, for amounts not covered by its insurance program.

Dotiki Mine Fire

On February 11, 2004, Webster County Coal, LLC’s (“Webster County Coal”) Dotiki mine was temporarily idled for a period of twenty-seven calendar days following the occurrence of a mine fire that originated with a diesel supply tractor (the “Dotiki Fire Incident”). As a result of the firefighting efforts of MSHA, the Kentucky Department of Mines and Minerals, and Webster County Coal personnel, Dotiki successfully extinguished the fire and totally isolated the affected area of the mine behind permanent barriers. Initial production resumed on March 8, 2004. For the Dotiki Fire Incident, the Partnership had commercial property insurance that provided coverage for damage to property destroyed, interruption of business operations, including profit recovery, and expenditures incurred to minimize the period and total cost of disruption to operations.

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On September 10, 2004, the Partnership filed a third and final proof of loss with the applicable insurance underwriters reflecting a settlement of all expenses, losses and claims incurred by Webster County Coal and other affiliates arising from or in connection with the Dotiki Fire Incident (the “Dotiki Insurance Claim”) in the aggregate amount of $27.0 million, inclusive of a $1.0 million self-retention, a $2.5 million deductible (collectively, the “2004 Insurance Deductibles”) and 10% co-insurance (the “2004 Co-Insurance”).

At March 31, 2004, the Dotiki Insurance Claim was in the early stages of being developed and the Partnership had recorded a recoverable insurance receivable of $2.9 million, net of the 2004 Insurance Deductibles and the 2004 Co-Insurance. The recognized net insurance receivable was reflected as an offset to operating expenses for the Partnership’s first quarter 2004 financial results.

5. NET INCOME PER LIMITED PARTNER UNIT

A reconciliation of net income and weighted average units used in computing basic and diluted earnings per unit is as follows (in thousands, except per unit data):

	Three Months Ended March 31,
	2005			2004
Net income	$	39,079		$	18,225
Adjustments:
General partners’ priority distributions		(922	)		—
General partners’ 2% equity ownership		(763	)		(365	)
Limited partners’ interest in net income	$	37,394		$	17,860
Weighted average limited partner units – basic		18,130			17,904
Basic net income per limited partner unit	$	2.06		$	1.00
Weighted average limited partner units – basic		18,130			17,904
Units contingently issuable:
Restricted units for Long-Term Incentive Plan		298			476
Directors’ compensation units deferred		18			15
Supplemental Executive Retirement Plan		50			44
Weighted average limited partner units, assuming dilutive effect of restricted units		18,496			18,439
Diluted net income per limited partner unit	$	2.02		$	0.97

The Partnership’s net income is allocated to the general partners and limited partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations, if any, to the Partnership’s general partners, which are declared and paid following the close of each quarter.

The Partnership’s Managing GP is entitled to receive incentive distributions if the amount the Partnership distributes with respect to any quarter exceeds levels specified in the First Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”). Under the quarterly incentive distribution provisions of the Partnership Agreement, generally, the Managing GP is entitled to receive 15% of the amount the Partnership distributes in excess of $0.55 per unit, 25% of the amount the Partnership distributes in excess of $0.625 per unit and 50% of the amount the Partnership distributes in excess of $0.75 per unit.

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6. RESTRICTED UNIT-BASED COMPENSATION

The Partnership accounts for the compensation expense of the non-vested restricted units granted under the Long-Term Incentive Plan using the intrinsic value method prescribed in Accounting Principles Board (“APB”) Opinion No. 25,Accounting for Stock Issued to Employees (“APB No. 25”) and the related Financial Accounting Standards Board (“FASB”) Interpretation No. 28,Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans. Compensation cost for the non-vested restricted units is recorded on a pro-rata basis, as appropriate, given the cliff vesting nature of the grants, based upon the current market value of the Partnership’s Common Units at the end of each period.

Consistent with the disclosure requirements of Statement of Financial Accounting Standards (“SFAS”) No. 148,Accounting for Stock-Based Compensation Transition and Disclosure, and amendment of SFAS No. 123,Accounting for Stock-Based Compensation, the following table provides pro forma results as if the fair value-based method had been applied to all outstanding and non-vested awards, including Long-Term Incentive Plan’s restricted units, in each period presented (in thousands, except per unit data):

	Three Months Ended March 31,
	2005			2004
Net income, as reported	$	39,079		$	18,225
Add: compensation expenses related to Long-Term Incentive Plan units included in reported net income		489			3,917
Deduct: compensation expense related to Long-Term Incentive Plan units determined under fair value method for all awards		(1,079	)		(1,143	)
Net income, pro forma	$	38,489		$	20,999
General partners’ interest in net income, pro forma	$	1,673		$	420
Limited partners’ interest in net income, pro forma	$	36,816		$	20,579
Earnings per limited partner unit:
Basic, as reported	$	2.06		$	1.00
Basic, pro forma	$	2.03		$	1.15
Diluted, as reported	$	2.02		$	0.97
Diluted, pro forma	$	1.99		$	1.12

The total accrued liability associated with the Long-Term Incentive Plan as of March 31, 2005 and December 31, 2004 was $10,502,000 and $10,013,000, respectively, and is included in the current and long-term due to affiliates liabilities in the condensed consolidated balance sheets. See Recent Accounting Pronouncements discussion below concerning the impact of SFAS No. 123R, share-based payment on accounting for the Long-Term Incentive Plan.

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7. COMPONENTS OF PENSION PLAN NET PERIODIC BENEFIT COSTS

Components of the net periodic costs for each of the periods presented are as follows (in thousands):

	Three Months Ended March 31,
	2005			2004
Service cost	$	813		$	705
Interest cost		417			357
Expected return on plan assets		(483	)		(421	)
Prior service cost		13			12
Net loss		50			35
Basic, as reported	$	810		$	688

The partnership previously disclosed in its financial statements for the year ended December 31, 2004, that it expected to contribute $2,700,000 to the Pension Plan in 2005. The Partnership typically makes a single contribution to its Pension Plan in the third quarter of a year. As of March 31, 2005, the Partnership had made no contributions to the Pension Plan in 2005.

8. RECENT ACCOUNTING PRONOUNCEMENTS

In November 2004, the FASB issued SFAS No. 151,Inventory Costs. SFAS No. 151 is an amendment of Accounting Research Bulletin (“ARB”) No. 43, chapter 4, paragraph 5 that deals with inventory pricing. SFAS No. 151 clarifies the accounting for abnormal amounts of idle facility expenses, freight, handling costs, and spoilage. Under previous guidance, paragraph 5 of ARB No. 43, chapter 4, items such as idle facility expense, excessive spoilage, double freight, and re-handling costs might be considered to be so abnormal, under certain circumstances, as to require treatment as current period charges. SFAS No. 151 eliminates the criterion of “so abnormal” and requires that those items be recognized as current period charges. Also, SFAS No. 151 requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No. 151 is effective for fiscal years beginning after June 15, 2005. The Partnership is analyzing the requirements of SFAS No. 151 and believes that its adoption will not have a significant impact on the Partnership’s financial position, results of operations or cash flows.

In December 2004, the FASB issued SFAS No. 123R,Share-Based Payment. SFAS No. 123R is a revision of SFAS No. 123,Accounting for Stock Based Compensation, and supersedes APB No. 25. Among other items, SFAS No. 123R eliminates the use of APB No. 25 and the intrinsic value method of accounting, and requires companies to recognize in their financial statements the cost of employee services received in exchange for awards of equity instruments, based on the grant date fair value of those awards.

In April 2005, the Securities and Exchange Commission issued a rule that amends the implementation dates for SFAS No. 123R from the third quarter of 2005 to the first quarter of 2006. SFAS No. 123R permits companies to adopt its requirements using either a “modified prospective” method, or a “modified retrospective” method. Under the “modified prospective” method, compensation cost is recognized in the financial statements beginning with the effective date, based on the requirements of SFAS No. 123R, for all share-based payments granted after the effective date of the rule and based on the requirements of SFAS No. 123 for all unvested awards granted prior to the effective date of SFAS No. 123R. Under the “modified retrospective” method, the requirements are the same as under the “modified prospective” method, but also permits entities to restate financial statements of previous periods based on pro forma disclosures made in accordance with SFAS No. 123. The Partnership is currently evaluating the appropriate transition method.

As permitted by SFAS No. 123, the Partnership currently accounts for unit-based payments to employees using the APB No. 25 intrinsic method and related FASB Interpretation No. 28 based upon the

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current market value of the Partnership’s common units at the end of each period. The Partnership has recorded compensation expense of $489,000 and $3,917,000 for the three months ended March 31, 2005 and 2004, respectively. SFAS No. 123R does not permit entities to continue to use the intrinsic method, the Partnership has not yet determined which model it will use to measure the fair value of restricted unit-based compensation upon the adoption of SFAS No. 123R.

In March 2005, the FASB Emerging Issues Task Force (“EITF”) issued EITF No. 04-06 Accounting for Stripping Costs in the Mining Industry and concluded that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. EITF No. 04-06 does not address the accounting for stripping costs incurred during the pre-production phase of a mine. EITF 04-06 is effective for the first reporting period in fiscal years beginning after December 15, 2005 with early adoption permitted. The effect of initially applying this consensus should be accounted for in a manner similar to a cumulative-effect adjustment. Since the Partnership has historically adhered to the accounting principles similar to EITF 04-06, the Partnership does not believe that adoption of EITF 04-06, effective January 1, 2006, will have a material impact on its consolidated financial statements.

9. SUBSEQUENT EVENTS

On April 20, 2005, the Partnership adopted Amendment No. 1 (“Amendment No.1”) which amends the Partnership Agreement. The effective date of Amendment No. 1 is January 1, 2005. Amendment No. 1 amends the provisions of the Partnership Agreement relating to priority allocations of gross income or gain with respect to the holders of incentive distribution rights and the general partners. Amendment No. 1 provides that, in addition to allocating this gross income or gain to the holders of incentive distribution rights in an amount equal to the incentive distributions received by such holders, a certain additional portion of gross income or gain should be allocated to the general partners of the Partnership.

On April 21, 2005, the Partnership declared a quarterly distribution, for the quarterly period ended March 31, 2005, of $0.75 per unit, totaling approximately $14.8 million (which includes the Managing GP’s portion of incentive distributions), on all of its Common Units outstanding, payable on May 13, 2005, to all unitholders of record as of May 6, 2005.

On April 19, 2005, counsel for the West Virginia Rivers Coalition, the West Virginia Highlands Conservancy, and Trout Unlimited – West Virginia Council (the “Appellants”) submitted a letter to OSM requesting the Director of OSM evaluate, consistent with its statutory oversight responsibilities, the State of West Virginia’s program in regard to the issuance of underground permits that will create acid mine drainage with no defined end point, particularly for the E-Mine. OSM issued a ten-day notice, dated April 21, 2005, to WVDEP advising a citizen’s complaint had been received alleging, among other matters, the underground permit for the E-Mine will cause material harm on and off-site of the permit area to the hydrological balance. WVDEP has requested an extension of time in which to respond and its response is due on or before June 8, 2005. We expect OSM will complete an evaluation of the citizen’s complaint and the response by WVDEP to the ten-day notice, and issue a determination on WVDEP’s approved state program on or before the end of May 2005. Management believes the WVDEP’s approval of the underground permit application will be ultimately upheld.

On April 26, 2005, two consolidated litigation matters concerning the underground permit for E-Mine that had been filed in state court in West Virginia were dismissed with prejudice, by mutual agreement of Mettiki (WV) and the Appellants. For a discussion of the underground mine permit process for the E-Mine, please read Note 2. “Contingencies” above.

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

SUMMARY

We reported record quarterly net income for the three months ended March 31, 2005 (the 2005 Quarter) of $39.1 million, an increase of 114.4% over the three months ended March 31, 2004 (the 2004 Quarter). We achieved record coal production and tons sold during the 2005 Quarter, which when combined with higher coal prices resulted in record revenue and net income. These records were achieved despite lost production, continuing fixed expenses, and other expenses incurred as a result of the MC Mining Fire Incident. See “Results of Operations – MC Mining Fire Incident” below. We continue to benefit from higher average sales prices reflecting the continuation of favorable coal markets partially offset by increased production costs.

We have contractual commitments for substantially all of our remaining estimated 2005 production. We are currently estimating 2006 production in the range of 23.0 million to 23.5 million tons, of which approximately 61% is committed under contracts with firm pricing, 19% is committed under contracts subject to market price negotiations and 20% is anticipated to be sold under future coal supply agreements.

In response to demand in the Illinois Basin, we previously entered into a coal supply arrangement with a third-party supplier. Our purchase tonnage requirements under this arrangement increased to 40,000 tons per month beginning January 1, 2005 and continuing through June 30, 2007.

RESULTS OF OPERATIONS

Three Months Ended March 31, 2005 Compared to Three Months Ended March 31, 2004

	March 31,				March 31,
	2005		2004		2005		2004
	(in thousands)				(per ton sold)
Tons sold		5,631		5,110		N/A		N/A
Tons produced		5,729		5,112		N/A		N/A
Coal sales	$	178,846	$	144,539	$	31.76	$	28.29
Operating expenses and outside purchases	$	123,510	$	105,393	$	21.93	$	20.62

Coal sales. Coal sales for the 2005 Quarter increased 23.7% to $178.8 million from $144.5 million for the 2004 Quarter. The increase of $34.3 million reflects higher sales volumes and higher prices reflecting continued strength in the coal markets. Tons sold were 5.6 million and 5.1 million for the 2005 and 2004 Quarters, respectively. Tons produced increased 12.1% to 5.7 million tons for the 2005 Quarter from 5.1 million for the 2004 Quarter.

Operating expenses. Operating expenses increased 14.4% to $119.4 million for the 2005 Quarter from $104.3 million for the 2004 Quarter. The increase of $15.1 million resulted from higher operating expenses due to increased coal sales volumes of 521,000 tons, increased materials and supply costs (particularly fuel, power and steel), maintenance expenses, sales-related expenses, and employee medical costs.

General and administrative. General and administrative expenses decreased to $5.7 million for the 2005 Quarter compared to $10.3 million for the 2004 Quarter. The decrease of $4.6 million was primarily attributable to lower incentive compensation expense which resulted from a decrease in the market value of our common units during the 2005 Quarter and a reduction in the number of restricted units outstanding due to the vesting in November 2004 of the Long-Term Incentive Plan units for grant years 2000 to 2002.

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Other sales and operating revenues. Other sales and operating revenues, which are primarily comprised of services to the coal synfuel production facility, increased 11.0% to $7.2 million for the 2005 Quarter from $6.5 million for the 2004 Quarter. The increase of $0.7 million is primarily attributable to transloading fees associated with the Mt. Vernon transfer terminal.

Outside purchases. Outside purchases increased to $4.1 million for the 2005 Quarter from $1.1 million in the 2004 Quarter. The increase of $3.0 million was primarily attributable to an increase in outside purchases, which also contributed to additional coal sales volumes, also at our Illinois Basin operations under the previously described coal supply arrangement with a third-party supplier.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $13.6 million for the 2005 Quarter compared to $12.8 million for the 2004 Quarter. The increase of $0.8 million was primarily the result of additional depreciation expense associated with increased capital expenditures and infrastructure investments over the last few years, which have increased our production capacity.

Interest expense. Interest expense was comparable for the 2005 and 2004 Quarters at $3.5 million and $3.8 million, respectively. We had no borrowings under the credit facility during the 2005 Quarter.

Transportation revenues and expenses. Transportation revenues and expenses increased to $9.6 million for the 2005 Quarter compared to $6.8 million for the 2004 Quarter. The increase of $2.8 million was primarily attributable to higher coal sales volumes for which we arrange transportation and increased shipments to customers with higher transportation costs.

Income before income taxes. Income before income taxes increased to $39.8 million for the 2005 Quarter from $19.0 million for the 2004 Quarter. The increase of $20.8 million is primarily attributable to increased sales volumes, higher coal prices and reduced general and administrative expenses, primarily reflecting lower incentive compensation expense, partially offset by higher operating expenses.

Income tax expense. Income tax expense was comparable at $0.7 million for each of the 2005 and 2004 Quarters, respectively.

MC Mining Mine Fire

On December 26, 2004, our MC Mining, LLC’s (MC Mining) Excel No. 3 mine was temporarily idled following the occurrence of a mine fire (the MC Mining Fire Incident). The fire was discovered by mine personnel near the bottom of the Excel No. 3 mine slope late in the evening of December 25, 2004.

Under a firefighting plan developed by MC Mining, in cooperation with mine emergency response teams from the U.S. Department of Labor’s Mine Safety and Health Administration (MSHA) and Kentucky Office of Mine Safety and Licensing, the four portals at the Excel No. 3 mine were temporarily capped to deprive the fire of oxygen. A series of boreholes was then drilled into the mine from the surface, and nitrogen gas and foam were injected through the boreholes into the fire area to further suppress the fire. As a result of these efforts, the mine atmosphere was rendered substantially inert, or without oxygen, and the Excel No. 3 mine fire was effectively suppressed. MC Mining then began construction of temporary and permanent barriers designed to completely isolate the mine fire area. Once the construction of the permanent barriers was completed, MC Mining began efforts to repair and rehabilitate the Excel No. 3 mine infrastructure. On February 21, 2005, the repair and rehabilitation

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efforts had progressed sufficiently to allow initial resumption of production. Production is gradually increasing to anticipated levels, but continues to be adversely impacted by inefficiencies attributable to or associated with the MC Mining Fire Incident.

We maintain commercial property (including business interruption and extra expense) insurance policies with various underwriters, which policies are renewed annually in October and provide for self-retention and various applicable deductibles, including certain monetary and/or time element forms of deductibles (collectively, the 2005 Deductibles) and 10% co-insurance (2005 Co-Insurance). We believe such insurance coverage will cover a substantial portion of the total cost of the disruption to MC Mining’s operations. However, until the claim is resolved ultimately, through either the claim adjustment process, settlement, or litigation, with the applicable underwriters, we can make no assurance of the amount or timing of recovery of insurance proceeds.

We made an initial estimate of certain costs primarily associated with activities relating to the suppression of the fire and the initial resumption of operations. Operating expenses for the 2004 fourth quarter were increased by $4.1 million to reflect an initial estimate of certain minimum costs attributable to the MC Mining Fire Incident that are not reimbursable under our insurance policies due to the application of the 2005 Deductibles and 2005 Co-Insurance.

On April 6, 2005, we submitted to a representative of the underwriters a preliminary estimate of the expenses and losses (including business interruption losses) incurred by MC Mining and other affiliates arising from or in connection with the MC Mining Fire Incident (the MC Mining Insurance Claim). The accounting for any future payments, if any, made to us by the underwriters will be subject to the accounting methodology described below. Currently, we continue to evaluate our potential insurance recoveries under the applicable insurance policies in the following areas:

1. Fire Brigade/Extinguishing/Mine Recovery Expense; Expenses to Reduce Loss; Debris Removal Expenses; Demolition and Increased Cost of Construction; Expediting Expenses; and Extra Expenses incurred as a result of the fire – These expenses and other costs (e.g. professional fees) associated with extinguishing the fire, reducing the overall loss, demolition of certain property and removal of debris, expediting the recovery from the loss, and extra expenses that would not have been incurred by us but for the MC Mining Fire Incident are being expensed as incurred with related actual and/or estimated insurance recoveries recorded as they are considered to be probable, up to the amount of the actual cost incurred.

2. Damage to MC Mining mine property - The net book value of property destroyed, which is currently estimated at $104,000, was written off in the first quarter of 2005 with a corresponding amount recorded as an estimated insurance recovery, since such recovery is considered probable. Any insurance proceeds from the claims relating to the MC Mining mine property (other than amounts relating to the matters discussed in 1. above) that exceed the net book value of such damaged property are expected to result in a gain. The anticipated gain will be recorded when the MC Mining Insurance Claim is resolved and/or proceeds are received.

3. MC Mining mine business interruption losses – We have submitted to a representative of the underwriters an initial business interruption loss analysis for the period of December 24, 2004 through March 31, 2005. Expenses associated with business interruption losses are expensed as incurred, and estimated insurance recoveries of such losses are recognized to the extent such recoveries are considered to be probable, up to the actual amount incurred. Recoveries in excess of actual costs incurred will be recorded as gains when the MC Mining Insurance Claim is resolved and/or proceeds are received.

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Pursuant to the accounting methodology described above, we have recorded $9.2 million as an offset to operating expenses during the three months ended March 31, 2005, which amount represents the current estimated insurance recovery of actual costs incurred, net of the 2005 Deductibles and 2005 Co-Insurance. We continue to discuss the MC Mining Insurance Claim and the determination of the total claim amount with representatives of the underwriters. The MC Mining Insurance Claim will continue to be developed as additional information becomes available and we have completed our assessment of the losses (including the methodologies associated therewith) arising from or in connection with the MC Mining Fire Incident. At this time, based on the magnitude and complexity of the MC Mining Insurance Claim, we are unable to reasonably estimate the total amount of the MC Mining Insurance Claim as well as its exposure, if any, for amounts not covered by our insurance program.

Dotiki Mine Fire

On February 11, 2004, our Webster County Coal, LLC’s (Webster County Coal) Dotiki mine was temporarily idled for a period of twenty-seven calendar days following the occurrence of a mine fire that originated with a diesel supply tractor (the Dotiki Fire Incident). As a result of the firefighting efforts of the Mine Safety and Health Administration, Kentucky Department of Mines and Minerals, and Webster County Coal personnel, Dotiki successfully extinguished the fire and totally isolated the affected area of the mine behind permanent barriers. Initial production resumed on March 8, 2004. For the Dotiki Fire Incident, we had commercial property insurance that provided coverage for damage to property destroyed, interruption of business operations, including profit recovery, and expenditures incurred to minimize the period and total cost of disruption to operations.

On September 10, 2004, we filed a third and final proof of loss with the applicable insurance underwriters reflecting a settlement of all expenses, losses and claims incurred by Webster County Coal and other affiliates arising from or in connection with the Dotiki Fire Incident (the Dotiki Insurance Claim) in the aggregate amount of $27.0 million, inclusive of a $1.0 million self-retention, a $2.5 million deductible (collectively, the 2004 Insurance Deductibles) and 10% co-insurance (the 2004 Co-Insurance).

At March 31, 2004, the Dotiki Insurance Claim was in the early stages of being developed. Through March 31, 2004, we recorded a recoverable insurance receivable of $2.9 million, net of the 2004 Insurance Deductible and the 2004 Co-Insurance. The recognized net insurance receivable was reflected as an offset to operating expenses for our first quarter 2004 financial results.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Cash provided by operating activities was $28.5 million for the 2005 Quarter compared to $34.5 million for the 2004 Quarter. The decrease in cash provided by operating activities was principally attributable to an increase in total working capital and the long-term portion of advance royalties, partially offset by increased income from operations. Total working capital changes include increased inventories and receivables due to increased sales and the recording of a $9.2 million receivable reflecting the current estimate of actual expenses related to the MC Mining Fire Incident that are considered probable of recovery under our insurance policies.

Net cash used in investing activities was $16.7 million for the 2005 Quarter compared to $9.6 million for the 2004 Quarter. The increase is primarily attributable to an increase in capital expenditures associated with the addition of a continuous mining unit at our Warrior mining complex and costs associated with the development of our Elk Creek mine. We are currently estimating total capital expenditures in 2005 to be $89.6, which includes $23.0 million for development of our Elk Creek mine.

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Total capital expenditures to develop Elk Creek are estimated to be $65.0 million. We expect to fund these capital expenditures with available cash and marketable securities on hand, future cash generated from operations and/or borrowings available under the revolving credit facility.

Net cash used in financing activities was $14.8 million for the 2005 Quarter compared to $10.3 million for the 2004 Quarter. The increase is attributable to increased distributions to partners in the 2005 Period.

Capital Expenditures

Capital expenditures increased to $16.9 million in the 2005 Quarter from $13.4 million in the 2004 Quarter. See discussion of “Cash Flows” above concerning the increase in capital expenditures.

Notes Offering and Credit Facility

Alliance Resource Operating Partners, L.P., our intermediate partnership, has $180 million principal amount of 8.31% senior notes due August 20, 2014, payable in ten equal annual installments of $18 million beginning in August 2005 with interest payable semiannually (the Senior Notes). On August 22, 2003, our intermediate partnership completed an $85 million revolving credit facility (the Credit Facility), which expires September 30, 2006. The Credit Facility replaced a $100 million credit facility that would have expired August 2004. We paid in full all amounts outstanding under the $100 million credit facility with borrowings of $20 million under the new Credit Facility. The interest rate on the Credit Facility is based on either (i) the London Interbank Offered Rate or (ii) the “Base Rate”, which is equal to the greater of the JPMorgan Chase Prime Rate or the Federal Funds Rate plus 1/2 of 1%, plus, in either case, an applicable margin. We incurred certain costs totaling $1.2 million associated with the Credit Facility. These costs have been deferred and are being amortized as a component of interest expense over the term of the Credit Facility. In March 2005, our intermediate partnership entered into Amendment No. 1 to our credit facility to increase the maximum capital expenditures from $50,600,000 and $50,200,000 for the years ending December 31, 2005 and 2006, respectively, to $125,000,000 for each of the years ended December 31, 2005 and 2006. We had no borrowings outstanding under the Credit Facility at March 31, 2005. Letters of credit can be issued under the Credit Facility not to exceed $30 million. Outstanding letters of credit reduce amounts available under the Credit Facility. At March 31, 2005, we had letters of credit of $9.0 million outstanding under the Credit Facility.

The Senior Notes and Credit Facility are guaranteed by all of the subsidiaries of our intermediate partnership. The Senior Notes and Credit Facility contain various restrictive and affirmative covenants, including restrictions on the amount of distributions by our intermediate partnership and the incurrence of other debt exceeding $35 million. The Senior Notes restrictions on distributions are consistent with the Partnership Agreement and the Credit Facility limit borrowings to fund distributions to $25,000,000. We were in compliance with the covenants of both the Credit Facility and Senior Notes at March 31, 2005.

We have previously entered into and have maintained specific agreements with two banks to provide additional letters of credit in an aggregate amount of $25.9 million to maintain surety bonds to secure our obligations for reclamation liabilities and workers’ compensation benefits. At March 31, 2005, we had $25.9 million in letters of credit outstanding under these agreements. Our special general partner guarantees these outstanding letters of credit.

RELATED PARTY TRANSACTIONS

In January 2005, we acquired Tunnel Ridge, LLC from an affiliate, Alliance Resource Holdings, LLC, for approximately $500,000 and the assumption of reclamation liabilities. The acquisition was reviewed by the board of directors of our managing general partner and its conflicts committee. Based

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upon their reviews, it was determined that this transaction reflected market-clearing terms and conditions. As a result, the board of directors of our managing general partner and its conflicts committee approved the Tunnel Ridge acquisition as fair and reasonable to us and our limited partners. Please see “Item 1. Financial Statements – Note 3, Acquisitions.”

We have continuing related party transactions with our managing general partner and our special general partner, including our special general partner’s affiliates. These related party transactions relate principally to the provision of administrative services by our managing general partner, 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, 2004, “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.

RECENT ACCOUNTING PRONOUNCEMENTS

In November 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 151,Inventory Costs. SFAS No. 151 is an amendment of Accounting Research Bulletin (ARB) No. 43, chapter 4, paragraph 5 that deals with inventory pricing. SFAS No. 151 clarifies the accounting for abnormal amounts of idle facility expenses, freight, handling costs, and spoilage. Under previous guidance, paragraph 5 of ARB No. 43, chapter 4, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs might be considered to be so abnormal, under certain circumstances, as to require treatment as current period charges. SFAS No. 151 eliminates the criterion of “so abnormal” and requires that those items be recognized as current period charges. Also, SFAS No. 151 requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No. 151 is effective for fiscal years beginning after June 15, 2005. We are currently analyzing the requirements of SFAS No. 151 and believe that its adoption will not have a significant impact on our financial position, results of operations or cash flows.

In December 2004, the FASB issued SFAS No. 123R,Share-Based Payment. SFAS No. 123R is a revision of SFAS No. 123,Accounting for Stock Based Compensation, and supersedes APB No. 25. Among other items, SFAS No. 123R eliminates the use of APB No. 25 and the intrinsic value method of accounting, and requires companies to recognize in the financial statements the cost of employee services received in exchange for awards of equity instruments, based on the grant date fair value of those awards.

In April 2005, the Securities and Exchange Commission issued a rule that amends the implementation dates for SFAS No. 123R from the third quarter of 2005 to the first quarter of 2006. SFAS No. 123R permits companies to adopt its requirements using either a “modified prospective” method, or a “modified retrospective” method. Under the “modified prospective” method, compensation cost is recognized in the financial statements beginning with the effective date, based on the requirements of SFAS No. 123R for all share-based payments granted after the effective date of the rule and based on the requirements of SFAS No. 123 for all unvested awards granted prior to the effective date of SFAS No. 123R. Under the “modified retrospective” method, the requirements are the same as under the “modified prospective” method, but also permits entities to restate financial statements of previous periods based on proforma disclosures made in accordance with SFAS No. 123. We are currently evaluating the appropriate transition method.

As permitted by SFAS No. 123, we currently account for unit-based payments to employees using the APB No. 25 intrinsic method and related FASB Interpretation No. 28 based upon the current market value of our common units at the end of each period. We have recorded compensation expense of

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$489,000 and $3,917,000 for the three months ended March 31, 2005 and 2004, respectively. SFAS No. 123R does not permit entities to continue to use the intrinsic method, we have not yet determined which model we will use to measure the fair value of restricted unit-based compensation upon the adoption of SFAS No. 123R.

In March 2005, the FASB Emerging Issues Task Force (“EITF”) issued EITF No. 04-06 Accounting for Stripping Costs in the Mining Industry and concluded that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. EITF No. 04-06 does not address the accounting for stripping costs incurred during the pre-production phase of a mine. EITF 04-06 is effective for the first reporting period in fiscal years beginning after December 15, 2005, with early adoption permitted. The effect of initially applying this consensus should be accounted for in a manner similar to a cumulative-effect adjustment. Since we have historically adhered to the accounting principles similar to EITF 04-06, we do not believe that adoption of EITF 04-06, effective January 1, 2006, will have a material impact on our consolidated financial statements.

RISK FACTORS

There were no significant changes in our risk factors as set forth in our Annual Report on Form 10-K for the year ended December 31, 2004 except as follows:

• Nonconventional source fuel tax credits are subject to a pro-rata phaseout or reduction based on the annual average wellhead price per barrel for all domestic crude oil (the reference price) as determined by the Secretary of the Treasury. The reference price is not subject to regulation by the United States. The reference price for a calendar year is typically published in April of the following year. The pro-rata reduction of nonconventional source fuel tax credits begins when the reference price is approximately $51.00 per barrel, with a complete phaseout or reduction of nonconventional synfuel tax credits when the reference price is approximately $64.00 per barrel. We could experience a reduction of revenues associated with nonconventional source fuel facilities if nonconventional source fuel tax credits become unavailable to the owners of the nonconventional source fuel facilities we service as a result of the rise in the wellhead price per barrel of crude oil above specified levels. At the present time, however we have not been advised of any reductions in coal feedstock supply requirements or related services provided to any of our nonconventional source fuel facility customers.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 did not engage in any interest rate, foreign currency exchange-rate or commodity price-hedging transactions as of March 31, 2005.

Borrowings under the Credit Facility and the previous credit facility are and were at variable rates and, as a result, we have interest rate exposure. Our earnings are not materially affected by changes in interest rates. We had no borrowings outstanding under the Credit Facility during the 2005 Quarter or at March 31, 2005.

As of March 31, 2005, the estimated fair value of the Senior Notes increased approximately $0.9 million due to slightly lower market interest rates in 2005. 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, 2004.

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ITEM 4. CONTROLS AND PROCEDURES

We maintain controls and procedures designed to ensure that we are able to collect the information we are required to disclose in the reports we file with the SEC, and to process, summarize and disclose this information within the time periods specified in the rules of the SEC. 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 the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive and Chief Financial Officers. Based on an evaluation of our disclosure controls and procedures as of the end of the period covered by this report conducted by our management, with the participation of our Chief Executive and Chief Financial Officers, our Chief Executive and Chief Financial Officers believe the design and operation of these controls and procedures are effective to ensure that the 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, 2005, 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. 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. These statements reflect our current views with respect to future events and are subject to various risks, uncertainties and assumptions. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

• 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;

• deregulation of the electric utility industry or the effects of any adverse change in the domestic 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 of, 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;

• 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;

• risk of major mine-related accidents or interruptions;

• results of litigation;

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

• difficulty obtaining commercial property insurance, and risks associated with our 10.0% participation (excluding any applicable deductible) in the commercial insurance property program; and

• Nonconventional source fuel tax credits are subject to a pro-rata phaseout or reduction based on the annual average wellhead price per barrel for all domestic crude oil (the reference price) as determined by the Secretary of the Treasury. We could experience a reduction of revenues associated with nonconventional source fuel facilities if nonconventional source fuel tax credits become unavailable to the owners of the nonconventional source fuel facilities we service as a result of the rise in the wellhead price per barrel of crude oil above specified levels.

If one or more of these 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 our Annual Report on Form 10-K for the year ended December 31, 2004. 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.

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You should consider the above information 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 persons acting on our behalf.

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PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The information under “Contingencies” in Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements 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, 2004.

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

4.1	Amendment No.1 dated as of April 20, 2005 to the First Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P. (Incorporated by reference to Exhibit 3.1 of the Registrant’s Form 8-K filed with the Commission on April 21, 2005, File No. 000-26823).
10.1	Amendment No. 1 dated January 17, 2005 to the Agreement for Supply of Coal between Virginia Electric and Power Company and Mettiki Coal, LLC. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 8-K filed with the Commission on January 19, 2005, 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 10, 2005, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 furnished herewith.
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 10, 2005, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 furnished herewith.
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 10, 2005, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 furnished herewith.

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32.2 Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated May 10, 2005, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 furnished 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 May 10, 2005.

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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EXHIBIT INDEX

Exhibit No.	Description
4.1	Amendment No.1 dated as of April 20, 2005 to the First Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P. (Incorporated by reference to Exhibit 3.1 of the Registrant’s Form 8-K filed with the Commission on April 21, 2005, File No. 000-26823).
10.1	Amendment No. 1 dated January 17, 2005 to the Agreement for Supply of Coal between Virginia Electric and Power Company and Mettiki Coal, LLC. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 8-K filed with the Commission on January 19, 2005, 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 10, 2005, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 furnished herewith.
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 10, 2005, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 furnished herewith.
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 10, 2005, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 furnished herewith.
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 10, 2005, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 furnished herewith.

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