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 September 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 ¨

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

As of November 9, 2005, 36,260,880 Common Units are outstanding.

TABLE OF CONTENTS


		Page
	PART I

	FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)

	ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

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

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

	Condensed Consolidated Statements of Cash Flows for the nine months ended September 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	26

ITEM 4.	CONTROLS AND PROCEDURES	26

	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 nine months ended September 30, 2004, as discussed in Note 12 to the condensed consolidated financial statements included in Item 1, Financial Statements (Unaudited). We previously computed net income per limited partner unit without applying certain provisions of Emerging Issues Task Force Issue No. 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. 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 No. 123. For additional information regarding the restatements, see “Notes 6, 7 and 12 to Financial Statements (Unaudited)” included in Item 1, Financial Statements (Unaudited).

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, quarterly cash distributions paid to common unitholders, or the condensed consolidated statements of cash flows.

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)


	September 30, 2005			December 31, 2004
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	38,770		$	31,177
Trade receivables, net		81,448			56,967
Other receivables		4,505			1,637
Marketable securities		49,472			49,397
Inventories		19,645			13,839
Advance royalties		2,481			3,117
Prepaid expenses and other assets		464			4,345

Total current assets		196,785			160,479
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment at cost		598,100			526,468
Less accumulated depreciation, depletion and amortization		(319,248	)		(292,900	)

Total property, plant and equipment		278,852			233,568
OTHER ASSETS:
Advance royalties		16,432			11,737
Coal supply agreements, net		681			2,723
Other long-term assets		5,967			4,277

Total other assets		23,080			18,737

TOTAL ASSETS	$	498,717		$	412,784

LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	45,860		$	30,961
Due to affiliates		15,840			10,338
Accrued taxes other than income taxes		11,507			10,742
Accrued payroll and related expenses		14,661			11,730
Accrued interest		1,421			5,402
Workers’ compensation and pneumoconiosis benefits		7,222			7,081
Other current liabilities		8,298			12,051
Current maturities, long-term debt		18,000			18,000

Total current liabilities		122,809			106,305
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities		144,000			162,000
Pneumoconiosis benefits		22,278			19,833
Workers’ compensation		30,293			25,994
Reclamation and mine closing		39,261			32,838
Due to affiliates		13,466			7,457
Other liabilities		4,197			3,170

Total long-term liabilities		253,495			251,292

Total liabilities		376,304			357,597

COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
Limited Partners - Common Unitholders 36,260,880 units outstanding		428,240			363,658
General Partners’ deficit		(300,634	)		(303,295	)
Unrealized loss on marketable securities		(71	)		(54	)
Minimum pension liability		(5,122	)		(5,122	)

Total Partners’ capital		122,413			55,187

TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	498,717		$	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 September 30,					Nine Months Ended September 30,
	2005		2004			2005		2004
SALES AND OPERATING REVENUES:
Coal sales	$	189,639	$	146,350		$	560,612	$	440,214
Transportation revenues		9,100		6,505			27,107		20,362
Other sales and operating revenues		8,304		5,406			23,667		18,055

Total revenues		207,043		158,261			611,386		478,631

EXPENSES:
Operating expenses		129,912		108,919			377,430		316,104
Transportation expenses		9,100		6,505			27,107		20,362
Outside purchases		3,472		2,410			10,981		4,274
General and administrative		12,812		12,687			29,067		34,292
Depreciation, depletion and amortization		13,798		13,620			40,822		39,806
Interest expense (net of interest income for the three and nine months ended September 30, 2005 and 2004 of $868, $215, $1,924 and $443, respectively)		2,841		3,672			9,685		11,351
Net gain from insurance settlement		—		(15,217	)		—		(15,217	)

Total operating expenses		171,935		132,596			495,092		410,972

INCOME FROM OPERATIONS		35,108		25,665			116,294		67,659
OTHER INCOME		90		202			314		761

INCOME BEFORE INCOME TAXES		35,198		25,867			116,608		68,420
INCOME TAX EXPENSE		717		546			2,256		2,013

NET INCOME	$	34,481	$	25,321		$	114,352	$	66,407

GENERAL PARTNERS’ INTEREST IN NET INCOME	$	2,908	$	843		$	7,617	$	2,235

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	31,573	$	24,478		$	106,735	$	64,172

BASIC NET INCOME PER LIMITED PARTNER UNIT ⁽¹⁾	$	0.65	$	0.53		$	2.09	$	1.45

DILUTED NET INCOME PER LIMITED PARTNER UNIT ⁽¹⁾	$	0.63	$	0.51		$	2.05	$	1.40

DISTRIBUTIONS PAID PER COMMON AND SUBORDINATED UNIT	$	0.41250	$	0.32500		$	1.16250	$	0.91875

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-BASIC		36,260,880		35,807,586			36,260,880		35,807,586

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-DILUTED		36,997,338		36,877,516			36,995,130		36,874,340

⁽¹⁾	Three and nine months ended September 30, 2004 restated, see Note 12.

See notes to condensed consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2005			2004
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	151,569		$	125,904

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property, plant and equipment		(78,973	)		(40,328	)
Proceeds from sale of property, plant and equipment		198			461
Purchase of marketable securities		(39,106	)		(4,969	)
Proceeds from marketable securities		39,014			13,672
Proceeds from assumption of liability		—			2,112

Net cash used in investing activities		(78,867	)		(29,052	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on long-term debt		(18,000	)		—
Distributions to Partners		(47,109	)		(34,165	)

Net cash used in financing activities		(65,109	)		(34,165	)

NET CHANGE IN CASH AND CASH EQUIVALENTS		7,593			62,687
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		31,177			10,156

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	38,770		$	72,843

CASH PAID FOR:
Interest	$	15,160		$	15,093

Income taxes to taxing authorities	$	2,675		$	2,150

NON-CASH INVESTING ACTIVITY
Purchase of property, plant and equipment	$	1,629		$	—

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

On September 15, 2005, the Partnership completed a two-for-one split of the Partnership’s common units, whereby holders of record at the close of business on September 2, 2005 received one additional common unit for each common unit owned on that date. The unit split resulted in the issuance of 18,130,440 common units. All references to the number of units and per unit net income and distribution amounts included in this report have been adjusted to give effect for this unit split for all periods presented.

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

These condensed consolidated financial statements and notes are prepared pursuant to the rules and regulations of the Securities and Exchange Commission for interim reporting and should be read in conjunction with the consolidated financial statements and notes included in 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 is developing an underground long-wall mining operation in Tucker County, West Virginia (the “Mountain View Mine,” also known as the “E-Mine”), which will eventually replace the Partnership’s Mettiki Coal, LLC’s existing long-wall mining operation at the D-Mine located in Garrett County, Maryland. The Mountain View Mine is located approximately 10 miles from Mettiki Coal. In order to proceed with development of the Mountain View Mine, Mettiki Coal (WV) submitted various permit applications to the West Virginia Department of Environmental Protection (“WVDEP”), including an application for approval to conduct underground mining. WVDEP issued the required permits in the spring of 2004. Certain complainants appealed WVDEP’s decision issuing the underground mining permit to the West Virginia Surface Mine Board (“SMB”), which held administrative hearings on the matter in late 2004 and early

2005. On March 8, 2005, the SMB issued a final order concluding consideration of the appeal without rendering a decision, which, by operation of West Virginia law, resulted in the affirmation of WVDEP’s decision to issue the underground mining permit. The complainants appealed the SMB decision, but subsequently voluntarily agreed to withdraw their appeal, which was dismissed with prejudice by the Tucker County Circuit Court in West Virginia on April 26, 2005.

On April 19, 2005, these same complainants submitted a letter to the United States Department of the Interior’s Office of Surface Mining, Reclamation and Enforcement (“OSM”), and the OSM’s regional field office in Charleston, West Virginia, (“CHFO”), requesting federal monitoring and inspection of the Mountain View Mine and alleging that operations at the mine would create acid mine drainage with no defined end point. By written notice, dated April 21, 2005, the CHFO advised WVDEP that it would review the complainant’s allegation that the Mountain View Mine would cause material harm to the hydrological balance within and outside of the permit area. Following its initial review, on September 15, 2005, the CHFO notified WVDEP that it intended to initiate a formal investigation into the issuance of the underground mining permit for the Mountain View Mine. WVDEP requested an informal review of the CHFO decision by the OSM, and by two letters, both dated October 21, 2005, (a) OSM reversed the decision of the CHFO concluding that the CHFO lacked statutory authority to review the WVDEP’s issuance of the underground mining permit and (b) the United States Department of the Interior advised the complainants that this was the Department of the Interior’s final decision of the matters raised in their letter of April 19, 2005. The Partnership is presently conducting mine development activities at the Mountain View Mine, and is not currently subject to any pending or threatened agency or third-party claims.

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 breach of contract and seeking declaratory relief to determine the parties’ rights under a coal sales agreement (the “Horizon Agreement”), dated October 3, 1998, as amended on February 28, 2001, between Horizon Natural Resource Sales Company (“Horizon Sales”), as buyer, and Pontiki Coal Corporation, as seller. 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 continued 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”) approximately 9,400 acres of land located in Ohio County, West Virginia and Washington County, Pennsylvania containing an estimated 70 million tons of high-sulfur coal in the

Pittsburgh No. 8 coal seam. Previously, in November 2004, the coal lease was amended to reduce the Tunnel Ridge reserve area from 50,571 acres to 9,400 acres to reflect the original intent of the parties and to correct an inadvertent mistake in the size of the leased reserve area. 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 described above was reviewed by the Board of Directors of Alliance Resource Management GP, LLC (the “Managing GP”) 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, LLC’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 has returned to levels that existed prior to the occurrence of the Vertical Belt Incident. The majority of repairs to the vertical belt conveyor system and ancillary equipment have been completed. The Partnership’s operating expenses were increased by $0.1 million and $2.9 million for the three and nine months ended September 30, 2005, respectively, to reflect the estimated direct expenses and costs attributable to the Vertical Belt Incident, which estimate included a $1.3 million retirement of the damaged vertical belt equipment. The Partnership has not identified currently any significant additional costs compared to the original cost estimates. The Partnership is conducting an analysis of all possible alternatives to mitigate the losses arising from the Vertical Belt Incident. This analysis will include a review of the Vertical Belt System Design, Supply, and Oversight of Installation Contract (“Installation Contract”), dated December 7, 2000, between White County Coal, LLC and Lake Shore Mining, Inc.. Until such analysis is completed, however, the Partnership can make no assurances of the amount or timing of recoveries, if any. Concurrent with the renewal of the Partnership’s commercial property (including business interruption) insurance policies concluded on October 31, 2005, White County Coal confirmed with the current underwriters of the commercial property insurance coverage that it would not file a formal insurance claim for losses arising from or in connection with the Vertical Belt Incident.

5.	MINE FIRE INCIDENTS

MC Mining Mine Fire

On December 26, 2004, MC Mining, LLC’s 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. Coal 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, concurrent with the renewal of the Partnership’s commercial property (including business interruption) insurance policies concluded on October 31, 2005, MC Mining confirmed with the current underwriters of the commercial property insurance coverage that any negotiated settlement of the losses arising from or in connection with the MC Mining Fire Incident would not exceed $40.0 million (inclusive of co-insurance and deductible amounts). 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.

Following the initial two submittals by the Partnership to a representative of the underwriters of its estimate of the expenses and losses (including business interruption losses) incurred by MC Mining and other affiliates arising from and in connection with the MC Mining Fire Incident (the “MC Mining Insurance Claim”), on September 15, 2005, the Partnership filed a third partial proof of loss, with an update through July 31, 2005. Partial payments of $4.2 million, $5.3 million, $1.5 million and $1.1 million were received from the underwriters in June, August, October and November of 2005, respectively. 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 of $154,000, 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 a business interruption loss analysis for the period of December 24, 2004 through July 31, 2005. Expenses associated with business interruption losses are expensed as incurred, and estimated insurance recoveries of such losses are

recognized to the extent such recoveries are considered to be probable, up to the actual amount incurred. Recoveries in excess of actual costs incurred will be recorded as gains when the MC Mining Insurance Claim is resolved and/or proceeds are received.

Pursuant to the accounting methodology described above, the Partnership has recorded as an offset to operating expenses, $9.2 million, $1.1 million and $0.3 million during the first, second, and third quarters of 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 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 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 of initial loss, a $2.5 million deductible and 10% co-insurance.

At September 30, 2004, the Partnership (a) had recorded as an offset to operating expenses, $2.8 million and $5.9 million during the three and nine months ended September 30, 2004, respectively, and (b) in the third quarter of 2004, recorded a combined net gain of approximately $15.2 million for damage to the property destroyed, interruption of business operations (including profit recovery), and extra expenses incurred to minimize the period and total cost of disruption to operations.

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 September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Net income	$	34,481		$	25,321		$	114,352		$	66,407
Adjustments:
General partners’ priority distributions		(2,264	)		(343	)		(5,439	)		(925	)
General partners’ 2% equity ownership		(644	)		(500	)		(2,178	)		(1,310	)

Limited partners’ interest in net income	$	31,573		$	24,478		$	106,735		$	64,172
Additional earnings allocation to general partners (a)		(8,104	)		(5,575	)		(30,931	)		(12,367	)

Net income available to limited partners under EITF No. 03-6 (a)		23,469			18,903			75,804			51,805

Weighted average limited partner units – basic		36,261			35,808			36,261			35,808

Basic net income per limited partner unit (a)	$	0.65		$	0.53		$	2.09		$	1.45

Weighted average limited partner units – basic		36,261			35,808			36,261			35,808
Units contingently issuable:
Restricted units for Long-Term Incentive Plan		597			944			597			944
Directors’ compensation units		38			34			37			32
Supplemental Executive Retirement Plan		101			92			100			90

Weighted average limited partner units, assuming dilutive effect of restricted units		36,997			36,878			36,995			36,874

Diluted net income per limited partner unit (a)	$	0.63		$	0.51		$	2.05		$	1.40

(a)

Basic and diluted net income per limited partner unit for the three and nine months ended September 30, 2004 have been restated to reflect application of Emerging Issues Task Force (“EITF”) No. 03-6, Participating Securities and the Two-Class Method Under FASB Statement No. 128. The dilutive effect of EITF No. 03-6 on basic net income per limited partner unit was $0.22 and $0.15 for the three months ended September 30, 2005 and 2004, respectively, and $0.85 and $0.34 for the nine months ended September 30, 2005 and 2004, respectively. The dilutive effect of EITF No. 03-6 on diluted net income per limited partner unit was $0.22 and $0.15 for the three months ended September 30, 2005 and 2004, respectively and $0.84 and $0.34 for the nine months ended September 30, 2005 and 2004, respectively. See Notes 7 and 12 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 the application of EITF No.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 Second 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 $0.275 per unit, 25% of the amount the Partnership distributes in excess of $0.3125 per unit and 50% of the amount the Partnership distributes in excess of $0.375 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 (“LTIP”) using the intrinsic value method prescribed in Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees 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 both the intrinsic value method and the provisions of SFAS No. 123 (in thousands, except per unit data):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Net income, as reported	$	34,481		$	25,321		$	114,352		$	66,407

Add: compensation expenses related to Long-Term Incentive Plan units included in reported net income		5,728			6,662			9,565			15,385
Deduct: compensation expense related to Long-Term Incentive Plan units determined under fair value method for all awards		(5,728	)		(6,662	)		(9,565	)		(15,385	)

Net income, pro forma	$	34,481		$	25,321		$	114,352		$	66,407

General partners’ interest in net income, pro forma	$	2,908		$	843		$	7,617		$	2,235

Limited partners’ interest in net income, pro forma	$	31,573		$	24,478		$	106,735		$	64,172

Earnings per limited partner unit:
Basic, as reported	$	0.65		$	0.53		$	2.09		$	1.45

Basic, pro forma	$	0.65		$	0.53		$	2.09		$	1.45

Diluted, as reported	$	0.63		$	0.51		$	2.05		$	1.40

Diluted, pro forma	$	0.63		$	0.51		$	2.05		$	1.40

Earnings per limited partner unit, basic and diluted, as reported, and basic and diluted, pro forma, for the three and nine months ended September 30, 2004 have been restated. See Notes 6 and 12 to the condensed financial statements for further discussion of this matter.

The total accrued liability associated with the LTIP as of September 30, 2005 and December 31, 2004 was $19,838,000 and $10,013,000, respectively, and is included in the current and long-term liabilities due to affiliates contained 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 LTIP.

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 September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Service cost	$	813		$	705		$	2,438		$	2,115
Interest cost		418			357			1,253			1,071
Expected return on plan assets		(483	)		(421	)		(1,448	)		(1,264	)
Prior service cost		13			12			38			36
Net loss		50			36			150			106

	$	811		$	689		$	2,431		$	2,064

As of September 30, 2005, the Partnership had made contributions of $3,000,000 to the Pension Plan in 2005.

9.	MINE DEVELOPMENT

The Partnership has mine development activities in progress at its Mountain View, Elk Creek and Pontiki underground mines. Mine development costs are capitalized and represent costs that establish access to mineral reserves and include costs associated with sinking or driving shafts and underground drifts, permanent excavations, roads and tunnels.

10.	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, Chapter 4, Paragraph 5 of ARB No. 43, 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 fair value of those awards on the grant date.

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, of 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 in the process of finalizing its evaluation of 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 $5,728,000, $6,662,000, $9,565,000 and $15,385,000 for the three and nine months ended September 30, 2005 and 2004, respectively.

In March 2005, the FASB issued EITF No. 04-6 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. 04-6 does not address the accounting for stripping costs incurred during the pre-production phase of a mine. EITF No. 04-6 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 would 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 No. 04-6 in accounting for stripping costs incurred at the Partnership’s surface operation, the Partnership does not believe that adoption of EITF No. 04-6, effective January 1, 2006, will have a material impact on its consolidated financial statements.

11.	SUBSEQUENT EVENTS

On October 23, 2005, the Partnership exercised its option to lease and/or sublease certain reserves from an affiliate, SGP Land, LLC, a subsidiary of ARH, which is a company owned by management, which reserves are contiguous to the Partnership’s Hopkins County Coal, LLC mining complex. Upon exercise of the option agreement, Hopkins County Coal entered into a Coal Lease and Sublease Agreement as well as a Royalty Agreement (collectively, the “Coal Lease Agreements”). The terms of the Coal Lease Agreements are through December 2015, with the right to extend the term for successive one-year periods for as long as the Partnership is mining within the coal field, as such term is defined in the Coal Lease Agreements.

The Coal Lease Agreements provide for five annual minimum royalty payments of $684,000 commencing in January 2006. The annual minimum royalty payments, consistent with the option agreement, and cumulative option fees of $3.4 million previously paid by the Partnership are fully recoupable against future tonnage royalty payments. Under the terms of the Coal Lease Agreements, Hopkins County Coal will also reimburse SGP Land for SGP Land’s base lease obligations.

On October 25, 2005, the Partnership’s Compensation Committee determined that the vesting requirement for the 2003 LTIP grants of 278,710 restricted units (net of 3,700 restricted unit forfeitures) had been satisfied as of September 30, 2005. As a result of this vesting, on November 1, 2005 the Partnership issued 165,426 Common Units to LTIP participants. The remaining units were settled in cash primarily to satisfy individual tax obligations of the LTIP participants.

On October 26, 2005, the Partnership declared a quarterly distribution for the quarterly period ended September 30, 2005, of $0.4125 per unit, totaling approximately $17.6 million (which includes the Managing GP’s incentive distributions), on all of its Common Units outstanding, payable on November 14, 2005, to all unitholders of record as of November 4, 2005.

On October 31, 2005, the Partnership completed its annual property and casualty insurance renewal with the various insurance coverages effective as of October 1, 2005. Available capacity for underwriting property insurance has tightened as a result of recent events including insurance carrier losses associated with U.S. gulf coast hurricanes, poor loss claims history in the underground coal mining industry and our recent loss history (i.e., Vertical Belt Incident, MC Mining Fire Incident, and Dotiki Fire Incident). As a result, the Partnership will retain a participating interest along with our insurance carriers at an average rate of approximately 10% in the $75 million commercial property program. The aggregate maximum limit in the

commercial property program is $75 million per occurrence of which we would be responsible for a maximum amount of $7.75 million for each occurrence, excluding a $1.5 million deductible for property damage and a 45-day waiting period for business interruption. As a result of the renewal for comparable levels of commercial property coverage, premiums for the property insurance program increased by approximately 130%. The Partnership can make no assurances that it will not experience significant insurance claims in the future, which as a result of the participation in the commercial property program, could have a material adverse effect on the business, financial conditions, results of operations and ability to purchase property insurance in the future.

12.	RESTATEMENTS

Net Income Per Limited Partner Unit

Subsequent to the issuance of the condensed consolidated financial statements for the three and nine months ended September 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 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 EITF No. 03-6. EITF No. 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 the three and nine months ended September 30, 2004 have been restated to reflect the pro forma distribution assumption required by EITF No. 03-6.

EITF No. 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 distribution, 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 No. 03-6 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 required under EITF No. 03-6) 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 actual and pro forma priority allocations. The remainder is then allocated between the limited partners and the general partners 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 September 30, 2004			Nine Months Ended September 30, 2004
As Previously Reported:
Basic net income per limited partner unit ⁽¹⁾	$	0.68		$	1.79
Diluted net income per limited partner unit ⁽¹⁾	$	0.66		$	1.74

After Application of EITF No. 03-6:
Basic net income per limited partner unit	$	0.53		$	1.45
Diluted net income per limited partner unit	$	0.51		$	1.40

Difference:
Basic net income per limited partner unit	$	(0.15	)	$	(0.34	)
Diluted net income per limited partner unit	$	(0.15	)	$	(0.34	)

⁽¹⁾	Amounts have been adjusted to give effect for a two-for-one split of the Partnership’s Common Units on September 15, 2005.

Common Unit-Based Compensation

Subsequent to the issuance of the condensed consolidated financial statements for the three and nine months ended September 30, 2004, 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 non-vested Common Units would be calculated utilizing a fair value model. The amounts have been restated to correctly calculate such common unit based compensation for non-vested Common Units based on an intrinsic value model. The correction of the error affected the pro forma disclosure, which also considers the impact of EITF No. 03-6 as follows:

As Previously Reported:


	Three Months Ended September 30, 2004			Nine Months Ended September 30, 2004
Net income, as reported	$	25,321		$	66,407

Add: compensation expenses related to Long-Term Incentive Plan units included in reported net income		6,662			15,385
Deduct: compensation expense related to Long-Term Incentive Plan units determined under fair value method for all awards		(1,122	)		(3,343	)

Net income, pro forma	$	30,861		$	78,449

General partners’ interest in net income, pro forma	$	953		$	2,475

Limited partners’ interest in net income, pro forma	$	29,908		$	75,974

Earnings per limited partner unit:
Basic, as reported ⁽¹⁾	$	0.68		$	1.79

Basic, pro forma ⁽¹⁾	$	0.84		$	2.12

Diluted, as reported ⁽¹⁾	$	0.66		$	1.74

Diluted, pro forma ⁽¹⁾	$	0.81		$	2.06

⁽¹⁾	Amounts have been adjusted to give effect for a two-for-one split of Partnership’s Common Units on September 15, 2005.

Restated:


	Three Months Ended September 30, 2004			Nine Months Ended September 30, 2004
Net income, as reported	$	25,321		$	66,407

Add: compensation expenses related to Long-Term Incentive Plan units included in reported net income		6,662			15,385
Deduct: compensation expense related to Long-Term Incentive Plan units determined under fair value method for all awards		(6,662	)		(15,385	)

Net income, pro forma	$	25,321		$	66,407

General partners’ interest in net income, pro forma	$	843		$	2,235

Limited partners’ interest in net income, pro forma	$	24,478		$	64,172

Earnings per limited partner unit:
Basic, as reported	$	0.53		$	1.45

Basic, pro forma	$	0.53		$	1.45

Diluted, as reported	$	0.51		$	1.40

Diluted, pro forma	$	0.51		$	1.40

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 nine months ended September 30, 2004.

We previously computed net income per limited partner unit without applying certain provisions of Emerging Issues Task Force (EITF) Issue No. 03-6, 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 No. 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 No. 123.

For additional information regarding the restatements, see Notes 6, 7 and 12 to the Unaudited Condensed Consolidated Financial Statements included in “Item 1, Financial Statements (Unaudited)”.

SUMMARY

We are a diversified producer and marketer of coal to major United States utilities and industrial users. We began mining operations in 1971 and, since then, have grown through acquisitions and internal development to become what we believe to be the fifth largest coal producer in the eastern United States. We

currently operate eight underground mining complexes in Illinois, Indiana, Kentucky, Maryland and West Virginia and one surface operation in Kentucky.

We reported quarterly net income for the three months ended September 30, 2005 (the 2005 Quarter) of $34.5 million, an increase of 36.2% over the three months ended September 30, 2004 (the 2004 Quarter). Results for the 2004 Quarter included the following unusual items: (1) a benefit of $18.0 million due to the final settlement of insurance claims attributable to the Dotiki Mine Fire described below and (2) $3.2 million of expense due to the buy-out of several coal sales contracts. There were no unusual items included in the results for the 2005 Quarter. During the 2005 Quarter, we continued to benefit from higher average sales prices reflecting the continuation of favorable coal markets, which benefit was 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 24.0 to 24.5 million tons, of which approximately 69% is committed under contracts with firm pricing, 19% is committed under contracts subject to market price negotiations and 12% 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 continues through June 30, 2007.

RESULTS OF OPERATIONS

Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004


	September 30,				September 30,
	2005		2004		2005		2004
	(in thousands)				(per ton sold)
Tons sold		5,589		5,111		N/A		N/A
Tons produced		5,351		4,886		N/A		N/A
Coal sales	$	189,639	$	146,350	$	33.93	$	28.63
Operating expenses and outside purchases	$	133,384	$	111,329	$	23.87	$	21.78

Coal sales. Coal sales increased 29.6% to $189.6 million for the 2005 Quarter from $146.4 million for the 2004 Quarter. The increase of $43.2 million was a result of increased sales volumes and higher coal sales prices reflecting continued strength in the coal markets. Tons sold increased 9.4% to 5.6 million tons for the 2005 Quarter from 5.1 million tons for the 2004 Quarter. Tons produced increased 9.5% to 5.4 million tons for the 2005 Quarter from 4.9 million for the 2004 Quarter.

Operating expenses. Operating expenses increased 19.3% to $129.9 million for the 2005 Quarter from $108.9 million for the 2004 Quarter. The increase of $21.0 million resulted from higher operating expenses due to increased coal sales volumes of 478,000 tons, higher labor and benefits costs, increased materials and supply costs (particularly steel, power and fuel), maintenance and repair expenses and sales-related expenses.

General and administrative. General and administrative expenses were comparable for the 2005 and 2004 Quarters at $12.8 million and $12.7 million, respectively.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of service revenue to coal synfuel production facilities and Mt. Vernon Transfer Terminal transloading fees. Other sales and operating revenues increased 53.6% to $8.3 million for the 2005 Quarter from $5.4 million for the 2004 Quarter. The increase of $2.9 million was primarily attributable to rental and service fees associated with a new third-party coal synfuel facility at the Gibson County Coal Operation, which began producing synfuel in May 2005, in addition to increased volumes at a third-party coal synfuel facility at Warrior.

Outside purchases. The increase in outside purchases to $3.5 million for the 2005 Quarter from $2.4 million in the 2004 Quarter was primarily attributable to the previously described coal supply arrangement with a third-party supplier, which also contributed to additional coal sales volumes at our Illinois Basin operations.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense was comparable at $13.8 million and $13.6 million for the 2005 and 2004 Quarters, respectively.

Interest expense. Interest expense decreased to $2.8 million for the 2005 Quarter from $3.7 million for the 2004 Quarter. The decrease of $0.9 million primarily 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 or 2004 Quarters.

Transportation revenues and expenses. Transportation revenues and expenses increased to $9.1 million for the 2005 Quarter compared to $6.5 million for the 2004 Quarter. The increase of $2.6 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 $35.2 million for the 2005 Quarter from $25.9 million for the 2004 Quarter. The increase of $9.3 million was primarily attributable to increased sales volumes and higher coal prices partially offset by higher operating expenses. Results for the 2004 Quarter included the following unusual items: (1) a benefit of $18.0 million due to the final settlement of insurance claims attributable to the Dotiki Mine Fire described below and (2) $3.2 million of expense due to the buy-out of several coal sales contracts. There were no unusual items included in the results for the 2005 Quarter.

Income tax expense. Income tax expense was comparable for the 2005 and 2004 Quarters at $0.7 million and $0.5 million, respectively.

Nine Months Ended September 30, 2005 compared to Nine Months Ended September 30, 2004

We reported net income for the nine months ended September 30, 2005 (the 2005 Period) of $114.4 million, an increase of 72.2% over the nine months ended September 30, 2004 (the 2004 Period). These results were achieved despite lost production, continuing fixed expenses, and other expenses incurred as a result of the MC Mining Fire and Pattiki Vertical Belt Incidents described below in the 2005 Period. The 2004 Period includes the impact of lost production, continuing fixed expenses and other expenses incurred as a result of the Dotiki Fire Incident, offset by the final settlement of an insurance claim with our insurance underwriters relating to the Dotiki Fire 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.


	September 30,				September 30,
	2005		2004		2005		2004
	(in thousands)				(per ton sold)
Tons sold		16,977		15,417		N/A		N/A
Tons produced		16,722		15,183		N/A		N/A
Coal sales	$	560,612	$	440,214	$	33.02	$	28.55
Operating expenses and outside purchases	$	388,411	$	320,378	$	22.88	$	20.78

Coal sales. Coal sales increased 27.3% to $560.6 million for the 2005 Period from $440.2 million for the 2004 Period. The increase of $120.4 million reflects increased sales volumes and higher coal sales prices. Tons sold increased 10.1% to 17.0 million tons for the 2005 Period from 15.4 million tons in the 2004. Tons produced increased 10.1% to 16.7 million tons for the 2005 Period from 15.2 million tons in the 2004 Period.

Operating Expenses. Operating expenses increased 19.4% to $377.4 million for the 2005 Period from $316.1 million for the 2004 Period. The increase of $61.3 million primarily resulted from an increase in operating expenses associated with additional coal sales of 1.6 million tons, higher labor and benefits costs, increased materials and supply costs (particularly steel, power and fuel), maintenance and repair expenses, and sales-related expenses. The 2005 Period was further impacted by $2.9 million of expenses related to the Pattiki Vertical Belt Incident along with expenses associated with the MC Mining Fire Incident, both of which are described below. The 2004 Period includes a $3.2 million buy-out expense of several coal contracts that allowed us to take advantage of higher spot coal prices in 2005 and out-of-pocket expenses related to the Dotiki Fire not offset by proceeds from the final settlement with our insurance underwriters. See Dotiki Fire Incident described below.

General and administrative. General and administrative expenses decreased to $29.1 million for the 2005 Period compared to $34.3 million for the 2004 Period. The decrease of $5.2 million primarily resulted from lower incentive compensation expense due to a reduction in the number of restricted units outstanding due to the vesting in November 2004 of the Long-Term Incentive Plan (LTIP) units for grant years 2000 to 2002.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of service revenue to coal synfuel production facilities and Mt. Vernon Transfer Terminal transloading fees. Other sales and operating revenues increased 31.1% to $23.7 million for the 2005 Period from $18.1 million for the 2004 Period. The increase of $5.6 million was primarily attributable to rental and service fees associated with a new third-party coal synfuel facility at the Gibson County Coal operation, which began producing synfuel in May 2005, in addition to increased volumes at a third-party coal synfuel facility at Warrior in addition to an increase in transloading fees associated with the Mt. Vernon Transfer Terminal.

Outside purchases. The increase in outside purchases of $6.7 million to $11.0 million for the 2005 Period compared to $4.3 million for the 2004 Period was primarily attributable to the previously described coal supply arrangement with a third-party supplier, which also contributed to additional coal sales volumes at our Illinois Basin operations.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense was comparable for the 2005 and 2004 Quarters at $40.8 million and $39.8 million, respectively.

Interest expense. Interest expense decreased to $9.7 million for the 2005 Period from $11.4 million for the 2004 Period. The decrease of $1.7 million resulted from increased interest income earned on increased 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 or 2004 Periods.

Transportation revenues and expenses. Transportation revenues and expenses increased to $27.1 million for the 2005 Period from $20.4 million for the 2004 Period. The increase of $6.7 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 $116.6 million for the 2005 Period from $68.4 million for the 2004 Period. The increase of $48.2 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. The 2004 Period includes a $3.2 million buy-out expense of several coal contracts which allowed us to take advantage of higher spot coal prices in 2005 in addition to the impact of lost production, continuing fixed expenses and other expenses incurred as a result of the Dotiki Fire Incident offset by the final settlement of an insurance claim with our insurance underwriters relating to the Dotiki Fire Incident described below.

Income tax expense. Income tax expense was comparable at $2.3 million and $2.0 million, respectively.

Long-Term Incentive Plan

On October 25, 2005, our compensation committee determined that the vesting requirements for the 2003 LTIP grants of 278,710 restricted units (net of 3,700 restricted unit forfeitures) had been satisfied as of September 30, 2005. As a result of this vesting, on November 1, 2005, we issued 165,426 common units to LTIP participants. The remaining units were settled in cash primarily to satisfy individual tax obligations of the LTIP participants.

Unit Split

On September 15, 2005, we completed a two-for-one split of our common units, whereby holders of record at the close of business on September 2, 2005 received one additional common unit for each common unit owned on that date. This unit split resulted in the issuance of 18,130,440 common units.

Pattiki Vertical Belt Incident

On June 14, 2005, our White County Coal, LLC’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 has returned to levels that existed prior to the occurrence of the Vertical Belt Incident. The majority of repairs to the vertical belt conveyor system and ancillary equipment have been completed. Our operating expenses were increased by $0.1 million and $2.9 million in the 2005 Quarter and 2005 Period, respectively, to reflect the estimated direct expenses and costs attributable to the Vertical Belt Incident, which estimate included a $1.3 million retirement of the damaged vertical belt equipment. We have not identified currently any significant additional costs compared to the original cost estimates. We are conducting an analysis of all possible alternatives to mitigate the losses arising from the Vertical Belt Incident. This analysis will include a review of the Vertical Belt System Design, Supply, and Oversight of Installation Contract (Installation Contract), dated December 7, 2000, between White County Coal, LLC and Lake Shore Mining, Inc. Until such analysis is completed, however, we can make no assurances of the amount or timing of recoveries, if any. Concurrent with the renewal of our commercial property (including business interruption) insurance policies concluded on October 31, 2005, White County Coal confirmed with the current underwriters of the commercial property insurance coverage that it would not file a formal insurance claim for losses arising from or in connection with the Vertical Belt Incident.

MC Mining Mine Fire

On December 26, 2004, our MC Mining, LLC’s 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. Coal 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.

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, concurrent with the renewal of our commercial property (including business interruption) insurance policies concluded on October 31, 2005, MC Mining confirmed with the current underwriters of the commercial property insurance coverage that any negotiated settlement of the losses arising from or in connection with the MC Mining Fire Incident would not exceed $40.0 million (inclusive of co-insurance and deductible amounts). 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.

Following the initial two submittals by us to the a representative of the underwriters of our 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 (MC Mining Insurance Claim), on September 15, 2005, we filed a third partial proof of loss, with an update through July 31 2005. Partial payments of $4.2 million, $5.3 million, $1.5 and $1.1 million were received from the underwriters in June, August, October and November 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 of $154,000, 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 a business interruption loss analysis for the period of December 24, 2004 through July 31, 2005. Expenses associated with business interruption losses are expensed as incurred, and estimated insurance recoveries of such losses are recognized to the extent such recoveries are considered to be probable, up to the actual amount incurred. Recoveries in

excess of actual costs incurred will be recorded as gains when the MC Mining Insurance Claim is resolved and/or proceeds are received.

Pursuant to the accounting methodology described above, we have recorded as an offset to operating expenses, $9.2 million, $1.1 million, and $0.3 million during the first, second, and third quarters of 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 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 of initial loss, a $2.5 million deductible and 10% co-insurance.

At September 30, 2004, we (a) had recorded as an offset to operating expenses, $2.8 million and $5.9 million during the 2004 Quarter and 2004 Period, respectively, and (b) in the 2004 Quarter, recorded a combined net gain of approximately $15.2 million for damage to the property destroyed, interruption of business operations (including profit recovery), and extra expenses incurred to minimize the period and total cost of disruption to operations.

Coal Supply Agreements

Seminole Electric Cooperative, Inc.

On October 25, 2005, Seminole Electric Cooperative, Inc. (Seminole) and Webster County Coal, LLC (successor-in-interest to Webster County Coal Corporation), White County Coal, LLC (successor-in-interest to White County Coal Corporation), and Alliance Coal, LLC, as successor-in-interest to MAPCO Coal Inc. and agent for Webster County Coal, LLC and White County Coal, LLC (Webster County Coal, LLC, White County Coal, LLC and Alliance Coal, LLC are hereinafter collectively referred to as the “Seller”) entered into an agreement (Amendment No. 4 to the Coal Supply Agreement) to amend their Restated and Amended Coal Supply Agreement between Seminole, Webster County Coal Corporation and White County Coal Corporation, dated February 1, 1986, as amended (Coal Supply Agreement). The Coal Supply Agreement requires the Seller to sell to Seminole, and Seminole to purchase, coal from the Seller’s mines for use in Seminole’s Plant Units 1 and 2 located in the State of Florida. The Coal Supply Agreement has a term beginning February 1, 1986 and continuing through December 31, 2010.

Amendment No. 4 to the Coal Supply Agreement amends certain provisions of the above-referenced Coal Supply Agreement to:

(1)

Effective September 1, 2005, terminate Amendment No. 3, dated January 1, 2003, to the Coal Supply Agreement (Amendment No. 3);

(2)

confirm, acknowledge and provide that the Coal Supply Agreement and Amendment No. 1, dated May 10, 1996, together contain the entire agreement between the parties as to coal produced, sold and delivered pursuant to the Coal Supply Agreement and provide that there are no representations, undertakings, or agreements, oral or written, which are not included in the Coal Supply Agreement and Amendment No. 1; and

(3)

confirm and acknowledge, to the best of Seller’s and Seminole’s respective knowledge and belief, that the Guaranty, signed by MAPCO Inc., now a subsidiary of The Williams Companies, remains in full force and effect.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Cash provided by operating activities was $151.6 million for the 2005 Period compared to $125.9 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 a sales driven increase in trade receivables, increased inventories due to increased production and a decrease in the total accrued liability for the LTIP included in the current and long-term liability due to affiliates resulting from the vesting in November 2004 of the 2000 to 2002 LTIP grants.

Net cash used in investing activities was $78.9 million for the 2005 Period compared to $29.1 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 $119.9 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. The increase was further impacted by proceeds from marketable securities, net of purchases of marketable securities, which occurred during the 2004 Period.

Net cash used in financing activities was $65.1 million for the 2005 Period compared to $34.2 million for the 2004 Period. The increase is attributable to a scheduled $18.0 million debt payment in August 2005 in addition to increased distributions to partners in the 2005 Period.

Capital Expenditures

Capital expenditures increased to $79.0 million in the 2005 Period from $40.3 million in the 2004 Period. See discussion of “Cash Flows” above concerning the increase in capital expenditures.

Insurance

On October 31, 2005, we completed our annual property and casualty insurance renewal, with the various insurance coverages effective as of October 1, 2005. Available capacity for underwriting property insurance has tightened as a result of recent events including insurance carrier losses associated with U.S. gulf coast hurricanes, poor loss claims history in the underground coal mining industry and our recent loss history (i.e., Vertical Belt Incident, MC Mining Fire Incident, and Dotiki Fire Incident described above). As a result, we will retain a participating interest along with our insurance carries at an average rate of approximately 10% in our $75 million commercial property program. The aggregate maximum limit in the commercial property program is $75 million per occurrence of which we would be responsible for a maximum amount of $7.75 million for each occurrence, excluding a $1.5 million deductible for property damage and a 45-day waiting

period for business interruption. As a result of the renewal for comparable levels of commercial property coverage, premiums for our property insurance program increased by approximately 130%. We can make no assurances that we will not experience significant insurance claims in the future, which as a result of our participation in the commercial property program, could have a material adverse effect on our business, financial condition, results of operations and ability to purchase property insurance in the future.

Notes Offering and Credit Facility

Alliance Resource Operating Partners, L.P., our intermediate partnership, has $162 million principal amount of 8.31% senior notes due August 20, 2014, payable in nine remaining equal annual installments of $18 million 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 September 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 September 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 September 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 September 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 (Unaudited) – Note 3. Tunnel Ridge Acquisitions.”

In October 2005, we exercised our option to lease and/or sublease certain reserves from an affiliate, SGP Land, LLC, a subsidiary of ARH, which is a company owned by management, which reserves are contiguous to our Hopkins County Coal, LLC mining complex. Upon exercise of the option agreement, Hopkins County Coal entered into a Coal Lease and Sublease Agreement as well as a Royalty Agreement (collectively, the Coal Lease Agreements). The terms of the Coal Lease Agreements are through December 2015, with the right to extend the term for successive one-year periods for as long as we are mining within the coal field, as such term is defined in the Coal Lease Agreements.

The Coal Lease Agreements provide for five annual minimum royalty payments of $684,000 commencing in January 2006. The annual minimum royalty payments, consistent with the option agreement and cumulative option fees of $3.4 million previously paid by us are fully recoupable against future tonnage royalty payments. Under the terms of the Coal Lease Agreements, Hopkins County Coal will also reimburse SGP Land for SGP Land’s base lease.

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, Chapter 4, Paragraph 5 of ARB No. 43, 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 Accounting Principles Board (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 fair value of those awards on the grant date.

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. We are in the process of finalizing our evaluation of 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 $5,728,000,

$6,662,000, $9,565,000 and $15,385,000 for the three and nine months ended September 30, 2005 and 2004, respectively.

In March 2005, the FASB issued EITF No. 04-6 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. 04-6 does not address the accounting for stripping costs incurred during the pre-production phase of a mine. EITF No. 04-6 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 would be accounted for in a manner similar to a cumulative-effect adjustment. Since we have historically adhered to the accounting principles similar to EITF No. 04-6 in accounting for stripping costs incurred at our surface operation, we do not believe that adoption of EITF No. 04-6, 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.

•

Our profitability may decline due to unanticipated mine operating conditions and other factors that are not within our control.

•

A shortage of skilled labor may make it difficult for ARLP to maintain labor productivity and competitive costs and could adversely affect our profitability.

•

Expansions we have completed since our formation, as well as expansions that we may undertake in the future, involve a number of risks, any of which could cause us not to realize the anticipated benefits.

•

The unavailability of an adequate supply of coal reserves that can be mined at competitive costs could cause our profitability to decline.

•

Mining in Central and Northern Appalachia areas is more complex and involves more regulatory constraints than mining in other areas of the United States, which could affect our operations and cost structures of these areas.

•

Unexpected increases in raw material costs could significantly impair our operating profitability.

•

We may be unable to obtain and/or renew permits necessary for our mining operations, which could reduce production, and negatively impact our cash flow and profitability.

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 September 30, 2005.

Borrowings under the Credit Facility and the previous credit facility are and were at variable rates and, as a result, we have interest rate exposure. Our earnings are not materially affected by changes in interest rates. We had no borrowings outstanding under the Credit Facility during the 2005 Quarter or at September 30, 2005.

As of September 30, 2005, the estimated fair value of the Senior Notes was approximately $176.3 million. The fair value of long-term debt is based on interest rates that we believe are currently available to us for issuance of debt with similar terms and remaining maturities. 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 SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure, an Amendment of FASB Statement No. 123 that pertains to the accounting treatment for 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 EITF No. 03-6, and 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.

SFAS No. 148 amends the disclosure requirement of SFAS No. 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 SFAS No. 123.

After management’s initial review of our accounting under EITF No. 03-6 and SFAS No. 148, on August 13, 2005, management recommended to the Audit Committee of the Board of Directors of Alliance Resource Management GP, LLC 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 Board of Directors 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 of previous filings, we reevaluated our disclosure controls and procedures. We concluded that the restatement of our financial statements to correctly apply EITF No. 03-6 and SFAS No. 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 No. 03-6 and SFAS No. 148 in an effort to ensure that the restated financial statements reflect all necessary adjustments. We had initially designed, and are continuing to evaluate new internal control procedures to help remediate these issues and to ensure future compliance with accounting pronouncements. The new internal control procedures will include (a) increasing the number of personnel responsible for financial reporting, (b) renewing the emphasis on the review of recent accounting pronouncements and (c) providing financial reporting personnel with additional research tools, including subscribing to a service that specializes in providing alerts and information concerning developments in accounting pronouncements. These new procedures will be implemented during the fourth quarter of 2005 with corresponding management testing of their effectiveness as of December 31, 2005. We believe these steps will 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 deems 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 third quarter of 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:

•

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

•

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

•

risks associated with the expansion of our operations and properties;

•

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

•

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

•

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

•

customer delays or defaults in making payments;

•

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

•

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

•

greater than expected increases in raw material costs;

•

greater than expected shortage of skilled labor;

•

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

•

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

•

greater than expected environmental regulation, costs and liabilities;

•

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

•

risk of major mine-related accidents, such as mine fires, or interruptions;

•

results of litigation;

•

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

•

a loss of the benefit from certain state tax credits;

•

difficulty obtaining commercial property insurance, and risks associated with our 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 or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind the risk factors described in 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:

•

in this Quarterly Report on Form 10-Q;

•

other reports filed by us with the SEC;

•

our press releases; and

•

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

PART II

OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

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


3.1		The Second 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 October 27, 2005, File No. 000-26823).

10.1		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).

10.2		Amendment No. 4 dated October 25, 2005, 2005, between Seminole Electric Cooperative, Inc. and Webster County Coal, LLC (successor-in-interest to Webster County Coal Corporation), White County Coal, LLC (successor-in-interest to White County Coal Corporation), and Alliance Coal, LLC, as successor-in-interest to Mapco Coal, Inc. and agent for Webster County Coal, LLC and White County Coal, LLC, to the Coal Supply Agreement. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 8-K filed with the Commission on October 26, 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 November 9, 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 November 9, 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 November 9, 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 November 9, 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 November 9, 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

3.1		The Second 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 October 27, 2005, File No. 000-26823).

10.1		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).

10.2		Amendment No. 4 dated October 25, 2005, 2005, between Seminole Electric Cooperative, Inc. and Webster County Coal, LLC (successor-in-interest to Webster County Coal Corporation), White County Coal, LLC (successor-in-interest to White County Coal Corporation), and Alliance Coal, LLC, as successor-in-interest to Mapco Coal, Inc. and agent for Webster County Coal, LLC and White County Coal, LLC, to the Coal Supply Agreement. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form 8-K filed with the Commission on October 26, 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 November 9, 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 November 9, 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 November 9, 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 November 9, 2005, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 furnished herewith.

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