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 June 30, 2005

¨	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 August 15, 2005, 18,130,440 Common Units are outstanding.

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION


		Page
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)

	ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

	Condensed Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004	1

	Condensed Consolidated Statements of Income for the three months and six months ended June 30, 2005 and 2004	2

	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 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	15

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	27

ITEM 4.	CONTROLS AND PROCEDURES	27

	FORWARD-LOOKING STATEMENTS	28

	PART II

	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS	30

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	30

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	30

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	30

ITEM 5.	OTHER INFORMATION	30

ITEM 6.	EXHIBITS	30

Explanatory Note

Basic and diluted net income per limited partner unit and the pro forma disclosure related to common unit-based compensation have been restated for the three and six months ended June 30, 2004 as discussed in Note 11 to the condensed consolidated financial statements included in Part I Item 1. We previously computed net income per limited partner unit without applying certain provisions of Emerging Issues Task Force Issue No. 03-6 (“EITF 03-6”), “Participating Securities and the Two-Class Method under FASB Statement No. 128”.

We previously disclosed pro forma information under Statement of Financial Accounting Standards (“SFAS”) No. 148, Accounting for Stock-Based Compensation Transition and Disclosure, assuming compensation expense for the non-vested restricted units granted would be different under our accounting method (the intrinsic method of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees) and the provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). Our previous disclosure has been restated since compensation expense for the non-vested restricted units granted is the same under the intrinsic method and the provisions of SFAS 123. For additional information regarding the restatements, see “Notes 6, 7 and 11 to Financial Statements (Unaudited)” included in Part I Item 1.

The restatements have no impact on previously reported income before income taxes, net income, limited partners’ interest in net income, the condensed consolidated balance sheets or the condensed consolidated statements of cash flows.

The Partnership is also filing contemporaneously with this Form 10-Q, its annual report on Form 10-K/A for the year ended December 31, 2004 and its quarterly report on Form 10-Q/A for the quarterly period ended March 31, 2005

PART 1

FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)


	June 30, 2005			December 31, 2004
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	55,157		$	31,177
Trade receivables, net		71,686			56,967
Other receivables		9,837			1,637
Marketable securities		49,336			49,397
Inventories		20,161			13,839
Advance royalties		2,493			3,117
Prepaid expenses and other assets		1,881			4,345

Total current assets		210,551			160,479

PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment at cost		564,764			526,468
Less accumulated depreciation, depletion and amortization		(310,734	)		(292,900	)

Total property, plant and equipment		254,030			233,568

OTHER ASSETS:
Advance royalties		17,416			11,737
Coal supply agreements, net		1,361			2,723
Other long-term assets		5,354			4,277

Total other assets		24,131			18,737

TOTAL ASSETS	$	488,712		$	412,784


LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	43,950		$	30,961
Due to affiliates		11,888			10,338
Accrued taxes other than income taxes		12,617			10,742
Accrued payroll and related expenses		13,188			11,730
Accrued interest		5,402			5,402
Workers’ compensation and pneumoconiosis benefits		7,023			7,081
Other current liabilities		11,452			12,051
Current maturities, long-term debt		18,000			18,000

Total current liabilities		123,520			106,305

LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities		162,000			162,000
Pneumoconiosis benefits		21,405			19,833
Workers’ compensation		28,806			25,994
Reclamation and mine closing		34,111			32,838
Due to affiliates		9,754			7,457
Other liabilities		3,687			3,170

Total long-term liabilities		259,763			251,292

Total liabilities		383,283			357,597


COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:
Limited Partners - Common Unitholders 18,130,440 units outstanding		411,624			363,658
General Partners’ deficit		(300,984	)		(303,295	)
Unrealized loss on marketable securities		(89	)		(54	)
Minimum pension liability		(5,122	)		(5,122	)

Total Partners’ capital		105,429			55,187

TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	488,712		$	412,784

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 June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
SALES AND OPERATING REVENUES:
Coal sales	$	192,127	$	149,325	$	370,973	$	293,864
Transportation revenues		8,384		7,019		18,007		13,857
Other sales and operating revenues		8,205		6,202		15,363		12,649

Total revenues		208,716		162,546		404,343		320,370


EXPENSES:
Operating expenses		128,125		102,857		247,518		207,185
Transportation expenses		8,384		7,019		18,007		13,857
Outside purchases		3,392		799		7,509		1,864
General and administrative		10,547		11,276		16,255		21,605
Depreciation, depletion and amortization		13,396		13,415		27,024		26,186
Interest expense (net of interest income for the three months and six months ended June 30, 2005 and 2004 of $583, $118, $1,056 and $228, respectively)		3,370		3,836		6,844		7,679

Total operating expenses		167,214		139,202		323,157		278,376

INCOME FROM OPERATIONS		41,502		23,344		81,186		41,994
OTHER INCOME		119		245		224		559

INCOME BEFORE INCOME TAXES		41,621		23,589		81,410		42,553
INCOME TAX EXPENSE		829		728		1,539		1,467

NET INCOME	$	40,792	$	22,861	$	79,871	$	41,086

GENERAL PARTNERS’ INTEREST IN NET INCOME	$	3,025	$	1,028	$	4,709	$	1,392

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	37,767	$	21,833	$	75,162	$	39,694

BASIC NET INCOME PER LIMITED PARTNER UNIT (1)	$	1.47	$	0.97	$	2.89	$	1.84

DILUTED NET INCOME PER LIMITED PARTNER UNIT (1)	$	1.44	$	0.94	$	2.83	$	1.78

DISTRIBUTIONS PAID PER COMMON AND SUBORDINATED UNIT	$	0.75	$	0.625	$	1.50	$	1.1875

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-BASIC		18,130,440		17,903,793		18,130,440		17,903,793

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-DILUTED		18,497,586		18,438,551		18,497,003		18,437,704

PRO FORMA NET INCOME PER LIMITED PARTNER UNIT ASSUMING TWO-FOR-ONE UNIT SPLIT ON SEPTEMBER 15, 2005:
PRO FORMA BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.73	$	0.49	$	1.44	$	0.92

PRO FORMA DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.72	$	0.47	$	1.41	$	0.89

(1)	Three months and six months ended June 30, 2004 are restated, see Note 11.

See notes to condensed consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended June 30,
	2005			2004
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	96,396		$	75,467


CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property, plant and equipment		(43,041	)		(25,114	)
Proceeds from sale of property, plant and equipment		193			458
Purchase of marketable securities		(24,373	)		—
Proceeds from marketable securities		24,399			3,661
Proceeds from assumption of liability		—			2,112

Net cash used in investing activities		(42,822	)		(18,883	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to Partners		(29,594	)		(21,940	)

Net cash used in financing activities		(29,594	)		(21,940	)


NET CHANGE IN CASH AND CASH EQUIVALENTS		23,980			34,644

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		31,177			10,156


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	55,157		$	44,880


CASH PAID FOR:
Interest	$	7,613		$	7,614

Income taxes to taxing authorities	$	1,900		$	1,300


NON-CASH INVESTING ACTIVITY
Purchase of property, plant and equipment	$	4,265		$	—

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

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 June 30, 2005 and December 31, 2004, and the results of its operations and cash flows for the three months and six months ended June 30, 2005 and 2004. All material intercompany transactions and accounts of the Partnership have been eliminated.

These condensed consolidated financial statements and notes thereto 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/A 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, is 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 an underground mine (the “Mountain View Mine,” also known as the “E-Mine”) under construction 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 approximately 10 miles from Mettiki Coal in Garrett County, Maryland. The Mountain View Mine will operate as an underground mining complex utilizing a longwall miner for the majority of its coal extraction as well as continuous mining units used to prepare the mine for future longwall mining.

Total development capital expenditures for the Mountain View Mine are estimated currently to be $30.4 million, all of which has been approved by the Board of Directors of Alliance Resource GP, LLC (the “Managing GP”). Of the total estimated capital amount, approximately $1.7 million was expended in

2004. The Partnership is estimating total capital expenditures in 2005 and 2006 of approximately $28.7 million to develop the Mountain View Mine, of which approximately $15.4 million is expected to be incurred in 2005, of which, $5.0 million of the year 2005 estimate had been expended at June 30, 2005. Initial production from development operations at the Mountain View Mine began in July 2005. In 2004, annual production from the existing Mettiki mining complex was 3.2 million tons. Following completion of the development of the Mountain View Mine, annual production for this mining complex is anticipated to be within the range of 2.7 to 3.2 million tons beginning in 2007, depending on market conditions at the time.

In order to proceed with the development of the Mountain View 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.

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, January 11, 2005 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 underground 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 Mountain View Mine. As part of their request, the Appellants asked the Director of OSM to initiate a federal monitoring and inspection review of the Mountain View 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 Mountain View Mine will cause material harm on and off-site of the permit area to the hydrological balance. The WVDEP and Mettiki Coal (WV) provided responses to the citizen’s complaint on or before June 8, 2005, the approved extended response deadline. On June 17, 2005, OSM indicated that it expects to provide a final response to the citizen’s complaint before the end of August 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. 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. VERTICAL BELT FAILURE

On June 14, 2005, White County Coal’s Pattiki mine was temporarily idled following the failure of the vertical conveyor belt system ( the “Vertical Belt Incident”) used in conveying raw coal out of the mine. White County Coal surface personnel detected a failure of the vertical conveyor belt on June 14, 2005 and immediately shut down operation of all underground conveyor belt systems. On July 20, 2005, White County Coal’s efforts to repair the vertical belt system had progressed sufficiently to allow it to perform a full test of the vertical belt system. After evaluating the test results, the Pattiki mine resumed initial production operations on July 21, 2005. Production of raw coal is approaching the level that existed prior to the occurrence of the Vertical Belt Incident. However, White County Coal will continue various repairs to the vertical belt conveyor system and ancillary equipment through the end of September 2005 during non-production hours. The Partnership’s operating expenses were increased by $2.8 million in the second quarter of 2005 to reflect the estimated direct expenses and costs attributable to the Vertical Belt Incident, which estimate included a $1.2 million retirement of the damaged vertical belt equipment. The Partnership is conducting an analysis of all possible alternatives to mitigate potential losses arising from the Vertical Belt Failure. This analysis will include a review of the Vertical Belt System Design, Supply, and Oversight of Installation Contract between White County Coal, LLC and Lake Shore Mining, Inc. dated December 7, 2000, as well as the Partnership’s commercial property (including business interruption) insurance policies, which policies provide for self-retention, various deductibles and 10% co-insurance. Until such analysis is completed, however, the Partnership can make no assurances of the amount or timing of recoveries, if any.

5. 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 has returned to near normal 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.

On May 23, 2005, the Partnership submitted to a representative of the underwriters an update to its April 6, 2005 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”). Partial payments of $4.2 million and $2.4 million were received from the underwriters in June 2005 and August 2005. In addition, in early August, the underwriters accepted a second partial proof of loss filed by the Partnership in the amount of $5.5 million, the receipt of which is expected to occur during the third quarter of 2005. The accounting for these partial payments and 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:

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.

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.

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 May 1, 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 as an offset to operating expenses, $1.1 million and $10.3 million during the three months and six months ended June 30, 2005, respectively, which amounts represent 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.

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 in the aggregate amount of $27.0 million, inclusive of a $1.0 million self-retention, a $2.5 million deductible and 10% co-insurance.

At June 30, 2004, the Partnership had recorded as an offset to operating expenses, $0.2 million and $2.9 million during the three months and six months ended June 30, 2004, respectively, which amounts represented the then current estimated insurance recovery of actual costs incurred net of the insurance deductible and 10% coinsurance. Also at June 30, 2004, the Partnership had deferred $1.4 million of an initial unallocated partial advance payment of $4.5 million.

6. 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 June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Net income	$	40,792		$	22,861		$	79,871		$	41,086
Adjustments:
General partners’ priority distributions		(2,254	)		(582	)		(3,175	)		(582	)
General partners’ 2% equity ownership		(771	)		(446	)		(1,534	)		(810	)

Limited partners’ interest in net income	$	37,767		$	21,833		$	75,162		$	39,694
Additional earnings allocation to general partners (a)		(11,172	)		(4,418	)		(22,827	)		(6,791	)

Net income available to limited partners (a)	$	26,595		$	17,415		$	52,335		$	32,903

Weighted average limited partner units – basic		18,130			17,904			18,130			17,904

Basic net income per limited partner unit (a)	$	1.47		$	0.97		$	2.89		$	1.84

Weighted average limited partner units – basic		18,130			17,904			18,130			17,904

Units contingently issuable:
Restricted units for Long-Term Incentive Plan		299			474			299			474
Directors’ compensation units		19			16			18			15
Supplemental Executive Retirement Plan		50			45			50			45

Weighted average limited partner units, assuming dilutive effect of restricted units		18,498			18,439			18,497			18,438

Diluted net income per limited partner unit (a)	$	1.44		$	0.94			2.83		$	1.78

(a) Basic and diluted net income per limited partner unit for the three months and six months ended June 30, 2004 has been restated to reflect application of EITF 03-6. The dilutive effect of EITF 03-6 on basic net income per limited partner unit was $0.61 and $0.25 for the three months ended June 30, 2005 and 2004, respectively, and $1.26 and $0.38 for the six months ended June 30, 2005 and 2004. The dilutive effect of EITF 03-6 on diluted net income per limited partner unit was $0.60 and $0.24 for the three months ended June 30, 2005 and 2004, respectively and $1.23 and $0.37 for the six months ended June 30, 2005 and 2004, respectively. See Notes 7 and 11 to the condensed financial statements for further discussion of this matter.

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. For purposes of computing basic and diluted net income per limited partner unit, in periods when the Partnership’s aggregate net income exceeds the aggregate distributions for such periods, an increased amount of net income is allocated to the general partner for the additional pro forma priority income attributable to application of EITF 03-6.

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.

7. 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 demonstrates that compensation cost for the non vested restricted units granted under the LTIP is the same under the intrinsic value method and the provisions of SFAS No. 123 (in thousands, except per unit data):


	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Net income, as reported	$	40,792		$	22,861		$	79,871		$	41,086

Add: compensation expenses related to Long-Term Incentive Plan units included in reported net income		3,532			4,807			4,021			8,724
Deduct: compensation expense related to Long-Term Incentive Plan units determined under fair value method for all awards		(3,532	)		(4,807	)		(4,021	)		(8,724	)

Net income, pro forma	$	40,792		$	22,861		$	79,871		$	41,086

General partners’ interest in net income, pro forma	$	3,025		$	1,028		$	4,709		$	1,392

Limited partners’ interest in net income, pro forma	$	37,767		$	21,833		$	75,162		$	39,694

Earnings per limited partner unit:
Basic, as reported	$	1.47		$	0.97		$	2.89		$	1.84

Basic, pro forma	$	1.47		$	0.97		$	2.89		$	1.84

Diluted, as reported	$	1.44		$	0.94		$	2.83		$	1.78

Diluted, pro forma	$	1.44		$	0.94		$	2.83		$	1.78

Earnings per limited partner unit, basic and diluted as reported and basic and diluted, pro forma for the three months and six months ended June 30, 2004 have been restated. See Note 11 to the condensed financial statements for further discussion of this matter.

The total accrued liability associated with the Long-Term Incentive Plan as of June 30, 2005 and December 31, 2004 was $14,034,000 and $10,013,000, respectively, and is included in the current and long-term due to affiliate’s 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.

8. 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 June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Service cost	$	812		$	705		$	1,625		$	1,410
Interest cost		418			357			835			714
Expected return on plan assets		(482	)		(422	)		(965	)		(843	)
Prior service cost		12			12			25			24
Net loss		50			35			100			70

	$	810		$	687		$	1,620		$	1,375

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 each year. As of June 30, 2005, the Partnership had made no contributions to the Pension Plan in 2005.

9. 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 the Partnership’s adoption of 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 current market value of the Partnership’s common units at the end of each period. The Partnership has recorded compensation expense of $3,532,000, $4,807,000, $4,021,000 and $8,724,000 for the three and six months ended June 30, 2005 and 2004, respectively.

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.

10. SUBSEQUENT EVENTS

On July 14, 2005 the Partnership entered into a forward contract to buy €65,310 Euro and sell $79,110 USD on August 15, 2005 and buy €1,050,403 Euro and sell $1,274,139 USD on September 15, 2005 to lock in the price of equipment purchases necessary to repair the Pattiki Vertical Belt (Note 4).

On July 27, 2005, the Partnership declared a quarterly distribution for the quarterly period ended June 30, 2005, of $0.825 per unit, totaling approximately $17.5 million (which includes the Managing GP’s incentive distributions), on all of its Common Units outstanding, payable on August 12, 2005, to all unitholders of record as of August 5, 2005.

On July 27, 2005, the Partnership also announced a two-for-one split of the Partnership’s common units. The unit split will take place in the form of a one unit distribution on each unit outstanding, with units to be distributed on September 15, 2005 to unitholders of record as of September 2, 2005. This unit split will result in the issuance of approximately 18.1 million common units. Pro forma earnings per share amounts on a post-split basis for the three months and six months ended June 30, 2005 and 2004 has been presented in the condensed consolidated statements of income. Following the unit split, the current quarterly distribution of $0.825 per unit will become $0.4125 per unit, or an annualized rate of $1.65 per unit.

On August 4, 2005, Virginia Electric and Power Company’s Mount Storm Power Station (“Mount Storm”) and Alliance Coal, LLC (Alliance Coal”) entered into Feedstock Agreement No. 2 (“Feedstock Agreement”). Pursuant to the Feedstock Agreement, Alliance Coal has agreed to sell to Mount Storm Supply, and Mount Storm Supply has agreed to purchase up to 225,000 tons of coal per month as mutually agreed by the parties. The Feedstock Agreement has a term beginning as of July 1, 2005, and continuing through December 31, 2007, with actual coal delivery to begin January 1, 2007. The Feedstock Agreement was entered into pursuant to the terms of several agreements with Virginia Power.

11. RESTATEMENTS

Net Income Per Limited Partner Unit

Subsequent to the issuance of its condensed consolidated financial statements for three and six months ended June 30, 2004, the Partnership determined that in periods in which aggregate net income exceeds the Partnership’s aggregate distributions, the Partnership is required to present earnings per unit as if all the earnings for the period were distributed, regardless of the pro forma nature of the allocation or whether the earnings would actually have been distributed during the period. This requirement reflects a

consensus reached by the FASB in Emerging Issues Task Force Issue No. 03-6 (“EITF 03-6”), “Participating Securities and the Two-Class Method under FASB Statement No. 128”. EITF 03-6 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. As a result, basic and diluted net income per limited partner unit for 2004, 2003 and 2002 have been restated to reflect the pro forma distribution assumption required by EITF 03-6.

EITF 03-6 does not impact the Partnership’s overall net income or other financial results, however, for periods in which aggregate net income exceeds the Partnership’s aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner unit. This result occurs as a larger portion of the Partnership’s aggregate earnings, as if distributed, is allocated to the incentive distribution rights held by the Managing GP, even though the Partnership makes cash distributions on the basis of cash available for distributions, not earnings, in any given accounting period. In accounting periods in which aggregate net income does not exceed the Partnership’s aggregate distributions for such period, EITF 03-06 does not have any impact on the Partnership’s earnings per unit calculation.

Basic and diluted net income per limited partner unit is calculated by dividing net income after deducting the amount allocated to the general partners’ interests, (which includes the Managing GP’s actual priority allocations paid and the pro forma priority allocations) by the weighted average number of outstanding limited partner units during the period. Partnership net income is first allocated to the Managing GP based on the amount of priority allocations. The remainder is then allocated between the limited partners and the general partners is based on percentage ownership in the Partnership.

The correction of the error decreased basic and diluted net income per limited partner unit as follows:


	Three Months Ended June 30,			Six Months Ended June 30,
	2004			2004
As Previously Reported:

Basic net income per limited partner unit	$	1.22		$	2.22
Diluted net income per limited partner unit	$	1.18		$	2.15

After Application of EITF 03-6:

Basic net income per limited partner unit	$	0.97		$	1.84
Diluted net income per limited partner unit	$	0.94		$	1.78

Difference:

Basic net income per limited partner unit	$	(0.25	)	$	(0.38	)
Diluted net income per limited partner unit	$	(0.24	)	$	(0.37	)

Common Unit-Based Compensation

Subsequent to the issuance of the financial statements, the Partnership determined that the Partnership’s pro forma limited partner unit based compensation disclosure was incorrect. The original disclosure assumed compensation expense for the nonvested common units would be calculated utilizing a fair value model. The amounts have been restated to correctly calculate such common unit based compensation for new vested common units based on an intrinsic value model. The correction of the error effected the pro forma disclosure while also considering the impact of EITF 03-06 is as follows:

As Previously Reported:


	Three Months Ended June 30,			Six Months Ended June 30,
	2004			2004

Net income, as reported	$	22,861		$	41,086


Add: compensation expenses related to Long-Term Incentive Plan units included in reported net income		4,807			8,724

Deduct: compensation expense related to Long-Term Incentive Plan units determined under fair value method for all awards		(1,079	)		(2,221	)


Net income, pro forma	$	26,589		$	47,589


General partners’ interest in net income, pro forma	$	1,102		$	1,522


Limited partners’ interest in net income, pro forma	$	25,487		$	46,067


Earnings per limited partner unit:
Basic, as reported	$	1.22		$	2.22

Basic, pro forma	$	1.42		$	2.57

Diluted, as reported	$	1.18		$	2.15

Diluted, pro forma	$	1.38		$	2.50

Restated:


	Three Months Ended June 30,			Six Months Ended June 30,
	2004			2004

Net income, as reported	$	22,861		$	41,086


Add: compensation expenses related to Long-Term Incentive Plan units included in reported net income		4,807			8,724

Deduct: compensation expense related to Long-Term Incentive Plan units determined under fair value method for all awards		(4,807	)		(8,724	)


Net income, pro forma	$	22,861		$	41,086


General partners’ interest in net income, pro forma	$	1,028		$	1,392


Limited partners’ interest in net income, pro forma	$	21,833		$	39,694


Earnings per limited partner unit:
Basic, as reported	$	0.97		$	1.84

Basic, pro forma	$	0.97		$	1.84

Diluted, as reported	$	0.94		$	1.78

Diluted, pro forma	$	0.94		$	1.78

Basic and diluted earnings per limited partner unit, as reported, reflect the application of EITF 03-6.

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

The financial statements in this Form 10-Q reflect restatements of basic and diluted net income per limited partner unit and the pro forma disclosure related to common unit-based compensation for the three and six months ended June 30, 2004.

We previously computed net income per limited partner unit without applying certain provisions of Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06”), “Participating Securities and the Two-Class Method under FASB Statement No. 123”. Our financial statements have been restated to adjust the historical presentation of net income per limited partner unit. The restatement has no impact on previously reported income before income taxes, net income, limited partners’ interest in net income, the condensed consolidated balance sheets or the condensed consolidated statements of cash flows.

We previously disclosed pro forma information assuming compensation expense for the non-vested restricted units granted would be different under our accounting method (the intrinsic method) and the provisions of SFAS 123. Our previous disclosure has been restated since compensation expense for the non-vested restricted units granted is the same under the intrinsic method and the provision of SFAS 123.

For additional information regarding the restatements, see “Notes 6, 7 and 11 to Financial Statements (Unaudited)” included in Part I Item I.

SUMMARY

We reported record quarterly net income for the three months ended June 30, 2005 (the 2005 Quarter) of $40.8 million, an increase of 78.4% over the three months ended June 30, 2004 (the 2004 Quarter). We achieved record 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 the impact from the Pattiki vertical belt failure (the “Pattiki Vertical Belt Incident”) described below. We continue to benefit from higher average sales prices reflecting the continuation of favorable coal markets, which benefit is 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 23.3 million to 23.8 million tons, of which approximately 65% is committed under contracts with firm pricing, 18% is committed under contracts subject to market price negotiations and 17% 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 June 30, 2005 Compared to Three Months Ended June 30, 2004


	June 30,				June 30,
	2005		2004		2005		2004
	(in thousands)				(per ton sold)
Tons sold		5,757		5,196		N/A		N/A
Tons produced		5,642		5,185		N/A		N/A
Coal sales	$	192,127	$	149,325	$	33.37	$	28.74
Operating expenses and outside purchases	$	131,517	$	103,656	$	22.84	$	19.95

Coal sales. Coal sales for the 2005 Quarter increased 28.7% to $192.1 million from $149.3 million for the 2004 Quarter. The increase of $42.8 million is a result of record sales volumes and higher

prices reflecting continued strength in the coal markets. Tons sold were 5.8 million and 5.2 million for the 2005 and 2004 Quarters, respectively. Tons produced increased 8.8% to 5.6 million tons for the 2005 Quarter from 5.2 million for the 2004 Quarter.

Operating expenses. Operating expenses increased 24.6% to $128.1 million for the 2005 Quarter from $102.9 million for the 2004 Quarter. The increase of $25.2 million resulted from higher operating expenses due to increased coal sales volumes of 561,000 tons, higher labor and benefits costs, increased materials and supply costs (particularly fuel, power and steel), maintenance expenses, and sales-related expenses. The 2005 Quarter was further impacted by $2.8 million of expenses related to the Pattiki Vertical Belt Incident described below.

General and administrative. General and administrative expenses decreased to $10.5 million for the 2005 Quarter compared to $11.3 million for the 2004 Quarter. The decrease of $0.8 million was primarily attributable to lower incentive compensation expense which resulted from 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.

Other sales and operating revenues. Other sales and operating revenues is principally comprised of service revenue to coal synfuel production facilities and Mt. Vernon Transfer Terminal transloading fees. Other sales and operating revenues increased 32.3% to $8.2 million for the 2005 Quarter from $6.2 million for the 2004 Quarter. The increase of $2.0 million is primarily attributable to additional rental and service fees associated with increased volumes at third-party coal synfuel facilities.

Outside purchases. Outside purchases increased to $3.4 million for the 2005 Quarter from $0.8 million in the 2004 Quarter. The increase of $2.6 million was primarily attributable to an increase in outside purchases, which also contributed to additional coal sales volumes, 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 was comparable at $13.4 million for each of the 2005 and 2004 Quarters, respectively.

Interest expense. Interest expense decreased to $3.4 million for the 2005 Quarter from $3.8 million for the 2004 Quarter. The decrease of $0.4 million resulted from increased interest income earned on marketable securities which is netted against interest expense in the condensed consolidated statements of income. We had no borrowings under the credit facility during the 2005 Quarter.

Transportation revenues and expenses. Transportation revenues and expenses increased to $8.4 million for the 2005 Quarter compared to $7.0 million for the 2004 Quarter. The increase of $1.4 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 $41.6 million for the 2005 Quarter from $23.6 million for the 2004 Quarter. The increase of $18.0 million is primarily attributable to increased sales volumes, higher coal prices and reduced general and administrative expenses, partially offset by higher operating expenses and expenses related to the Pattiki Vertical Belt Incident described below.

Income tax expense. Income tax expense was comparable for the 2005 and 2004 Quarters at $0.8 million and $0.7 million, respectively.

Six Months Ended June 30, 2005 compared to Six Months Ended June 30, 2004

We reported record net income for the six months ended June 30, 2005 (the 2005 Period) of $79.9 million, an increase of 94.4% over the six months ended June 30, 2004 (the 2004 Period). We achieved record coal production and tons sold during the 2005 Period, 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 and Pattiki Vertical Belt Incident described below. We continue to benefit from higher average sales prices reflecting the continuation of favorable coal markets partially offset by increased production costs.


	June 30,				June 30,
	2005		2004		2005		2004
	(in thousands)				(per ton sold)
Tons sold		11,388		10,306		N/A		N/A
Tons produced		11,371		10,297		N/A		N/A
Coal sales	$	370,973	$	293,864	$	32.58	$	28.51
Operating expenses and outside purchases	$	255,027	$	209,049	$	22.39	$	20.28

Coal sales. Coal sales for the 2005 Period increased 26.2% to $371.0 million from $293.9 million for the 2004 Period. The increase of $77.1 million reflects record sales volumes and higher prices. Tons sold increased 10.5% to 11.4 million tons for the 2005 Period from 10.3 million tons in the 2004. Tons produced increased 10.4% to 11.4 million tons for the 2005 Period from 10.3 million tons in the 2004 Period.

Operating Expenses. Operating expenses increased 19.5% to $247.5 million for the 2005 Period from $207.2 million for the 2004 Period. The increase of $40.3 million primarily resulted from an increase in operating expenses associated with additional coal sales of 1.1 million tons, higher labor and benefits costs, increased materials and supply costs (particularly fuel, power and steel), maintenance expenses, and sales-related expenses. The 2005 Period was further impacted by $2.8 million of expenses related to the Pattiki Vertical Belt Incident along with expenses associated with the MC Mining Fire Incident, both incidents are described below.

General and administrative. General and administrative expenses decreased to $16.3 million for the 2005 Period compared to $21.6 million for the 2004 Period. The decrease of $5.3 million resulted from 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.

Other sales and operating revenues. Other sales and operating revenues is principally comprised of service revenue to coal synfuel production facilities and Mt. Vernon Transfer Terminal transloading fees. Other sales and operating revenues increased 21.5% to $15.4 million for the 2005 Period from $12.6 million for the 2004 Period. The increase of $2.8 million is primarily attributable to additional rental and service fees associated with increased volumes at third-party coal synfuel facilities.

Outside purchases. Outside purchases increased to $7.5 million for the 2005 Period compared to $1.9 million for the 2004 Period. The increase of $5.6 million was primarily attributable to an increase in outside purchases, which also contributed to additional coal sales volumes 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 was comparable for the 2005 and 2004 Quarters at $27.0 million and $26.2 million, respectively.

Interest expense. Interest expense decreased to $6.8 million for the 2005 Period from $7.7 million for the 2004 Period. The decrease of $0.9 million resulted from increased interest income earned on marketable securities which is netted against interest expense in the condensed consolidated statements of income. We had no borrowings under the credit facility during the 2005 Period.

Transportation revenues and expenses. Transportation revenues and expenses increased to $18.0 million for the 2005 Period from $13.9 million for the 2004 Period. The increase of $4.1 million was attributable primarily to higher 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 $81.4 million for the 2005 Period from $42.6 million for the 2004 Period. The increase of $38.8 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 and expenses related to the Pattiki Vertical Belt Incident and MC Mining Fire Incident described below.

Income tax expense. Income tax expense was comparable at $1.5 million for each of the 2005 and 2004 Periods, respectively.

Unit Split

On July 27, 2005, we announced a two-for-one split of our common units. The unit split will take place in the form of a one unit distribution on each unit outstanding, with units to be distributed on September 15, 2005 to unitholders of record as of September 2, 2005. This unit split will result in the issuance of approximately 18.1 million common units. Following the unit split, the current quarterly distribution of $0.825 per unit will become $0.4125 per unit, or an annualized rate of $1.65 per unit.

Pattiki Vertical Belt Incident

On June 14, 2005, our White County Coal, LLC’s (White County Coal) Pattiki mine was temporarily idled following the failure of the vertical conveyor belt system (the Vertical Belt Incident) used in conveying raw coal out of the mine. White County Coal surface personnel detected a failure of the vertical conveyor belt on June 14, 2005 and immediately shut down operation of all underground conveyor belt systems. On July 20, 2005, White County Coal’s efforts to repair the vertical belt system had progressed sufficiently to allow it to perform a full test of the vertical belt system. After evaluating the test results, the Pattiki mine resumed initial production operations on July 21, 2005. Production of raw coal is approaching the level that existed prior to the occurrence of the Vertical Belt Incident. However, White County Coal will continue various repairs to the vertical belt conveyor system and ancillary equipment through the end of September 2005 during non-production hours. Our operating expenses were increased by $2.8 million in the 2005 Quarter to reflect the estimated direct expenses and costs attributable to the Vertical Belt Incident, which estimate included a $1.2 million retirement of the damaged vertical belt equipment. We are conducting an analysis of all possible alternatives to mitigate potential losses arising from the Vertical Belt Failure. This analysis will include a review of the Vertical Belt System Design, Supply, and Oversight of Installation Contract between White County Coal, LLC and Lake Shore Mining, Inc. dated December 7, 2000, as well as our commercial property (including business interruption) insurance policies, which policies provide for self-retention, various deductibles and 10% co-insurance. Until such analysis is completed, however, we can make no assurances of the amount or timing of recoveries, if any.

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.

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 May 23, 2005, we submitted to a representative of the underwriters an update to its April 6, 2005 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”). Partial payments of $4.2 million and $2.4 million were received from the underwriters in June 2005 and August 2005. In addition, in early August, the underwriters accepted a second partial proof of loss filed by us in the amount of $5.5 million, the receipt of which is expected to occur during the third quarter of 2005. The accounting for these partial payments and 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:

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.

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.

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 May 1, 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, we have recorded as an offset to operating expenses, $1.1 million and $10.3 million during the three months and six months ended June 30, 2005, respectively, which amounts represent 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 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, 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 in the aggregate amount of $27.0 million, inclusive of a $1.0 million self-retention, a $2.5 million deductible and 10% co-insurance.

At June 30, 2004, we had recorded as an offset to operating expenses, $0.2 million and $2.9 million during the 2004 Quarter and 2004 Period, respectively, which amounts represented the then

current estimated insurance recovery of actual costs incurred net of the insurance deductible and 10% coinsurance. Also at June 30, 2004, we had deferred $1.4 million of an initial unallocated partial advance payment of $4.5 million.

Coal Supply Agreements

Virginia Electric and Power Company

On June 22, 2005, Virginia Electric and Power Company (Virginia Power) and Alliance Coal, LLC (Alliance Coal), our subsidiary, entered into a new seven-year Agreement for the Supply of Coal to the Mount Storm Power Station, dated June 22, 2005 (New Coal Supply Agreement). Pursuant to the New Coal Supply Agreement, Alliance Coal has agreed to sell to Virginia Power, and Virginia Power has agreed to purchase, coal from various production sources controlled by Alliance Coal for use in Virginia Power’s Mount Storm Power Station located in Grant County, West Virginia (Mount Storm Station). Under the terms of the New Coal Supply Agreement, Alliance Coal will annually deliver approximately 2.25 million tons of coal to the Mount Storm Station beginning January 1, 2007. As part of our obligation to supply coal under the New Coal Supply Agreement, Alliance Coal and/or its subcontractor(s) are required to construct various coal handling facilities located at the Mount Storm Station.

In connection with the New Coal Supply Agreement, Alliance Coal and/or our Mettiki Coal, LLC (Mettiki), our subsidiary entered into several agreements with Virginia Power: an Ancillary Services Agreement (Ancillary Services Agreement), an Amended and Restated Lease Agreement (Amended Lease Agreement), an Amended and Restated Equipment Lease Agreement (Existing Truck Unloading Facility) (Amended Equipment Lease), and an Amended and Restated Memorandum of Understanding (Amended Memorandum of Understanding).

Pursuant to the Ancillary Services Agreement, Alliance Coal will operate, use, maintain and repair various coal handling facilities at the Mount Storm Station. The Amended Lease Agreement extends to the term of the Lease Agreement effective as of January 15, 1996, as amended (Existing Lease), on the terms provided in the Amended Lease Agreement. The Amended Equipment Agreement extends the term of the Equipment Lease, effective as of January 15, 1996 (Existing Equipment Lease), on the terms provided in the Amended Equipment Lease. The Existing Lease and the Existing Equipment Lease were entered into in accordance with the Agreement for the Supply of Coal to the Mt. Storm Power Station, effective January 15, 1996, as amended (the Existing Coal Supply Agreement and together with the New Coal Supply Agreement, the Coal Supply Agreements).

Mettiki currently sells coal to Virginia Power for use at the Mount Storm Station pursuant to the terms of the Existing Coal Supply Agreement. The Existing Coal Supply Agreement will expire in accordance with its terms on December 31, 2006. Mettiki and Virginia Power from time to time may enter into, and Alliance Coal and Virginia Power may enter into, spot sale and purchase agreements for the delivery of Mettiki coal to the Mount Storm Station that are in addition to the parties’ purchase and sales obligations under the Coal Supply Agreements (Spot Agreement(s)).

Prior to Alliance Coal and Mt. Storm Coal Supply, LLC (Mt. Storm Supply) entering into Feedstock Agreement No. 2, dated as of July 1, 2005 (Feedstock Agreement) described below, Virginia Power had entered into various transactions with Mount Storm Supply and its affiliate, PC West Virginia Synthetic Fuel #2, LLC (PCWV#2), whereby PCWV#2 produced synthetic fuel that qualified for Section 29 tax credits that was derived from coal (Coal Synfuel) at PCWV#2’s synthetic fuel facility (Synfuel Facility), which Synfuel Facility was operated and maintained by PCWV#2 adjacent to or near the Mount Storm Station.

Pursuant to the Coal Supply Agreements and the Amended Memorandum of Understanding, Virginia Power, Alliance Coal and Mettiki agreed to certain terms and conditions that provided Mount Storm Supply the ability to purchase coal from Alliance Coal and/or Mettiki, which in turn was sold by Mount Storm Supply to PCWV#2 to produce Synfuel at PCWV#2’s Coal Synfuel Facility, which was then purchased by Virginia Power under synfuel supply agreements (Synfuel Supply Agreement(s)) between PCWV#2 and Virginia Power. Under the Coal Supply Agreements and the Amended Memorandum of Understanding, the Coal Synfuel purchased by Virginia Power from PCWV#2 under the Synfuel Supply Agreements, which was produced from coal supplied to Mount Storm Supply by Alliance Coal and/or Mettiki, reduced the quantity of coal that was otherwise required to be purchased by Virginia Power from Alliance Coal or Mettiki, as appropriate, under the New Coal Supply Agreement, the Existing Coal Supply Agreement and/or Spot Agreement(s).

Mount Storm Coal Supply, LLC

On August 4, 2005, Mount Storm Coal Supply and Alliance Coal entered into the Feedstock Agreement. Pursuant to the Feedstock Agreement, Alliance Coal has agreed to sell to Mount Storm Supply, and Mount Storm Supply has agreed to purchase, up to 225,000 tons of coal per month as mutually agreed by the parties. The Feedstock Agreement has a term beginning as of July 1, 2005, and continuing through December 31, 2007, with actual coal delivery to begin January 1, 2007. The Feedstock Agreement was entered into pursuant to the terms of the Amended and Restated Memorandum of Understanding, among Virginia Electric, Alliance Coal and Mettiki. The Amended Memorandum of Understanding was entered into in connection with the existing Coal Supply Agreement between Virginia Power and Alliance Coal. The Feedstock Agreement may be terminated by either Alliance Coal or Mount Storm Supply on seven (7) days prior written notice to the other if the tax credits under Section 29 of the Internal Revenue Code of 1986, as amended (Section 29 tax credits), which arise from the production and sale of synthetic fuel derived from the coal are not longer available or are materially reduced.

Forward Contract

On July 14, 2005 we entered into a forward contract to buy €65,310 Euro and sell $79,110 USD on August 15, 2005 and buy €1,050,403 Euro and sell $1,274,139 USD on September 15, 2005 to lock in the price of equipment purchases associated with the Pattiki Vertical Belt Incident described above.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Cash provided by operating activities was $96.4 million for the 2005 Period compared to $75.5 million for the 2004 Period. The increase in cash provided by operating activities was principally attributable to an increase in net income partially offset by an increase in total working capital. Total working capital changes include increased inventories and receivables due to increased production and sales and a $6.1 million receivable reflecting the current estimate of actual expenses related to the MC Mining Fire Incident that are considered probable of recovery but not yet collected from the underwriters under our insurance policies, partially offset by an increase in accounts payable due to higher operating costs.

Net cash used in investing activities was $42.8 million for the 2005 Period compared to $18.9 million for the 2004 Period. 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 at the Elk Creek and Mountain View mines along with construction to transition the Pontiki mine into a new coal seam. We are currently estimating total capital expenditures in

2005 to be approximately $115.0 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 $29.6 million for the 2005 Period compared to $21.9 million for the 2004 Period. The increase is attributable to increased distributions to partners in the 2005 Period.

Capital Expenditures

Capital expenditures increased to $43.0 million in the 2005 Period from $25.1 million in the 2004 Period. 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 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 June 30, 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 June 30, 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 June 30, 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 June 30, 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 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, Tunnel Ridge 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/A 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 the Partnership’s adoption of 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 $3,532,000, $4,807,000, $4,021,000 and $8,724,000 for the three and six months ended June 30, 2005 and 2004, respectively.

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/A for the year ended December 31, 2004 except as follows:

•

Non-conventional source fuel tax credits are subject to a pro-rata phase-out 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 Government. The reference price for a calendar year is typically published in April of the following year. For qualified fuel sold during the 2004 calendar year, the reference price was $36.75. The pro-rata reduction of non-conventional source fuel tax credits for 2004 would have begun if the reference price was approximately $51.00 per barrel, with a complete phase-out or reduction of non-conventional synfuel tax credits if the reference price reached approximately $64.00 per barrel. We could experience a reduction of revenues associated with non-conventional source fuel facilities in the future if non-conventional source fuel tax credits become unavailable to the owners of the non-conventional 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 non-conventional 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 June 30, 2005. However on July 14, 2005 we entered into a forward contract to buy €65,310 Euro and sell $79,110 USD on August 15, 2005 and buy €1,050,403 Euro and sell $1,274,139 USD on September 15, 2005 to lock in the price of equipment purchases necessary to repair the Pattiki Vertical Belt, see discussion of “Pattiki Vertical Belt” above.

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 June 30, 2005.

As of June 30, 2005, the estimated fair value of the Senior Notes increased approximately $1.3 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.

ITEM 4. CONTROLS AND PROCEDURES

Restatement of Previous Filings

In August 2005, we identified adjustments that were required to be recorded in prior periods relating to the way we (a) compute basic and diluted earnings per limited partner and (b) present the disclosures required by Statement of Financial Accounting Standard No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure, an Amendment of FASB Statement No. 123” associated with our Long Term Incentive Plan. Descriptions of these adjustments follow:

The Partnership determined that in periods in which aggregate net income exceeds the Partnership’s aggregate distributions, the Partnership is required to present net income per limited partner unit as if all the earnings for the period were distributed, regardless of the pro forma nature of the allocation or whether the earnings would or could actually have been distributed during the period. This requirement reflects a consensus reached by the FASB in Emerging Issues Task Force Issue No. 03-6 (“EITF 03-6”), “Participating Securities and the Two-Class Method under FASB Statement No. 128”. EITF 03-6 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock.

Statement of Financial Accounting Standard No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure, an Amendment of FASB Statement No. 123” (SFAS 148) amends the disclosure requirement of SFAS 123 to require more prominent disclosures in both annual and interim financial statements regarding the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Partnership’s previous disclosure provided pro forma information assuming compensation expense for the non-vested restricted units granted would be different under the intrinsic method and the provisions of SFAS123.

After management’s initial review of our accounting under EITF 03-6 and SFAS 148, on August 13, 2005, management recommended to the Audit Committee that, upon completion of our analysis of the impact of the items described above, our previously filed financial statements be restated to reflect the correction of these items. The Audit Committee agreed with this recommendation. On August 15, 2005, upon completion of our analysis, the Audit Committee approved our restated financial statements that were included in Amendment No. 1 to each of our Form 10-K for the year ended December 31, 2004 and Form 10-Q for the quarter ended March 31, 2005, each of which was filed with the SEC on August 15, 2005.

Evaluation of Disclosure Controls and Procedures

In connection with the restatement, we reevaluated our disclosure controls and procedures. We concluded that the restatement of our financial statements to correctly apply EITF 03-6 and SFAS 148, constituted a material weakness in our internal control over financial reporting. Solely as a result of this material weakness, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of June 30, 2005.

Remediation of Material Weakness in Internal Control

During August 2005 we performed an extensive review of our accounting under EITF 03-6 and SFAS 148 in an effort to ensure that the restated financial statements reflect all necessary adjustments. We have designed and are in the process of designing new internal control procedures to help remediate the issues and to ensure future compliance with accounting pronouncements. We believe we have taken the steps necessary to remediate this material weakness relating to our compliance with accounting standards; however, we cannot confirm the effectiveness of our internal controls with respect to our application of accounting standards until we have conducted sufficient testing. Accordingly, we will continue to monitor vigorously the effectiveness of these processes, procedures and controls and will make any further changes management determines appropriate.

Changes in Internal Controls.

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of our internal controls performed during the second quarter 2005 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. 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:

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

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

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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;

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

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customer bankruptcies and/or cancellations of, or breaches to existing contracts;

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customer delays or defaults in making payments;

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

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

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

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

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greater than expected environmental regulation, costs and liabilities;

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

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risk of major mine-related accidents or interruptions;

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results of litigation;

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

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

•

Non-conventional source fuel tax credits are subject to a pro-rata phase-out 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 non-conventional source fuel facilities if non-conventional source fuel tax credits become unavailable to the owners of the non-conventional 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/A 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.

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

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in this Quarterly Report on Form 10-Q;

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other reports filed by us with the SEC;

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our press releases; and

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

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).

10.2		Agreement for the Supply of Coal to the Mount Storm Power Station, dated June 22, 2005, between Virginia Electric and Power Company and Alliance Coal, LLC. (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K filed with the Commission on June 27, 2005, File No. 000-26823).

10.3		Ancillary Services Agreement, dated June 22, 2005, between Virginia Electric and Power Company and Alliance Coal, LLC. (Incorporated by reference to Exhibit 10.2 of the Registrant’s Form 8-K filed with the Commission on June 27, 2005, File No. 000-26823).

10.4		Amended and Restated Lease Agreement, dated June 22, 2005, 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 June 27, 2005, File No. 000-26823).


10.5		Amended and Restated Equipment Lease Agreement (Existing Truck Unloading Facility), dated June 22, 2005, between Virginia Electric and Power Company and Mettiki Coal, LLC. (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form 8-K filed with the Commission on June 27, 2005, File No. 000-26823).

10.6		Amended and Restated Memorandum of Understanding dated as of June 22, 2005, among Virginia Electric and Power Company, Alliance Coal, LLC and Mettiki Coal, LLC. (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form 8-K filed with the Commission on June 27, 2005, File No. 000-26823).

10.7		Feedstock Agreement No. 2, dated as of July 1, 2005, between Alliance Coal, LLC and Mount Storm Coal Supply, LLC. (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K filed with the Commission on August 5, 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 August 15, 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 August 15, 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 August 15, 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 August 15, 2005, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 furnished 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 August 15, 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

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).

10.2		Agreement for the Supply of Coal to the Mount Storm Power Station, dated June 22, 2005, between Virginia Electric and Power Company and Alliance Coal, LLC. (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K filed with the Commission on June 27, 2005, File No. 000-26823).

10.3		Ancillary Services Agreement, dated June 22, 2005, between Virginia Electric and Power Company and Alliance Coal, LLC. (Incorporated by reference to Exhibit 10.2 of the Registrant’s Form 8-K filed with the Commission on June 27, 2005, File No. 000-26823).

10.4		Amended and Restated Lease Agreement, dated June 22, 2005, 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 June 27, 2005, File No. 000-26823).

10.5		Amended and Restated Equipment Lease Agreement (Existing Truck Unloading Facility), dated June 22, 2005, between Virginia Electric and Power Company and Mettiki Coal, LLC. (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form 8-K filed with the Commission on June 27, 2005, File No. 000-26823).

10.6		Amended and Restated Memorandum of Understanding dated as of June 22, 2005, among Virginia Electric and Power Company, Alliance Coal, LLC and Mettiki Coal, LLC. (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form 8-K filed with the Commission on June 27, 2005, File No. 000-26823).

10.7		Feedstock Agreement No. 2, dated as of July 1, 2005, between Alliance Coal, LLC and Mount Storm Coal Supply, LLC. (Incorporated by reference to Exhibit 10.1 of the Registrant’s Form 8-K filed with the Commission on August 5, 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 August 15, 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 August 15, 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 August 15, 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 August 15, 2005, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 furnished herewith.

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