Alliance Resource Partners (ARLP) 10-Q 2004 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2004

OR

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

For the transition period from            to            

Commission File No.: 0-26823

ALLIANCE RESOURCE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware	73-1564280
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

1717 South Boulder Avenue, Suite 600, Tulsa, Oklahoma 74119

(Address of principal executive offices and zip code)

(918) 295-7600

(Registrant’s telephone number, including area code)

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

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

As of November 8, 2004, 18,132,609 Common Units are outstanding.

TABLE OF CONTENTS

PART I FINANCIAL INFORMATION
		Page
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)
	ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
	Condensed Consolidated Balance Sheets as of September 30, 2004 and December 31, 2003	1
	Condensed Consolidated Statements of Income for the three months and nine months ended September 30, 2004 and 2003	2
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2004 and 2003	3
	Notes to Condensed Consolidated Financial Statements	4
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	11
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	20
ITEM 4.	CONTROLS AND PROCEDURES	20
	FORWARD-LOOKING STATEMENTS	21
PART II OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	22
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	22
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	22
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	22
ITEM 5.	OTHER INFORMATION	22
ITEM 6.	EXHIBITS	22

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PART 1

FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

	September 30, 2004			December 31, 2003
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	72,843		$	10,156
Trade receivables, net		57,374			38,305
Marketable securities		15,014			23,615
Inventories		13,983			14,527
Advance royalties		1,108			1,108
Prepaid expenses and other assets		5,684			3,432
Total current assets		166,006			91,143
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment at cost		511,108			474,357
Less accumulated depreciation, depletion and amortization		(280,471	)		(251,567	)
Total property, plant and equipment, net		230,637			222,790
OTHER ASSETS:
Advance royalties		13,829			12,439
Coal supply agreements, net		3,404			5,445
Other long-term assets		4,066			4,637
Total other assets		21,299			22,521
TOTAL ASSETS	$	417,942		$	336,454
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	37,646		$	22,651
Due to affiliates		24,074			13,546
Accrued taxes other than income taxes		10,843			10,375
Accrued payroll and related expenses		16,065			11,095
Accrued interest		1,662			5,402
Workers’ compensation and pneumoconiosis benefits		5,941			5,905
Other current liabilities		6,516			5,739
Current maturities, long-term debt		18,000			—
Total current liabilities		120,747			74,713
LONG-TERM LIABLITIES:
Long-term debt, excluding current maturities		162,000			180,000
Accrued pneumoconiosis benefits		19,229			17,633
Workers’ compensation		27,139			22,819
Reclamation and mine closing		30,085			21,717
Due to affiliates		9,993			3,735
Other liabilities		3,848			3,280
Total long-term liabilities		252,294			249,184
Total liabilities		373,041			323,897
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL (DEFICIT):
Common Unitholders 14,692,527 units outstanding,		288,735			263,071
Subordinated Unitholder 3,211,266 units outstanding		64,020			58,411
General Partners		(304,065	)		(305,034	)
Unrealized loss on marketable securities		—			(102	)
Minimum pension liability		(3,789	)		(3,789	)
Total Partners’ capital		44,901			12,557
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	417,942		$	336,454

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except unit and per unit data)

(Unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2004			2003		2004			2003
SALES AND OPERATING REVENUES:
Coal sales	$	146,350		$	131,131	$	440,214		$	368,170
Transportation revenues		6,505			5,231		20,362			14,617
Other sales and operating revenues		5,406			5,437		18,055			17,408
Total revenues		158,261			141,799		478,631			400,195
EXPENSES:
Operating expenses		108,919			98,464		316,104			276,149
Transportation expenses		6,505			5,231		20,362			14,617
Outside purchases		2,410			3,844		4,274			5,233
General and administrative		12,687			6,494		34,292			18,799
Depreciation, depletion and amortization		13,620			12,556		39,806			39,349
Interest expense (net of interest income and interest capitalized for the three-months and nine-months ended September 30, 2004 and 2003 of $215, $83, $443, and $450 respectively)		3,672			4,088		11,351			12,045
Net gain from insurance settlement		(15,217	)		—		(15,217	)		—
Total operating expenses		132,596			130,677		410,972			366,192
INCOME FROM OPERATIONS		25,665			11,122		67,659			34,003
OTHER INCOME		202			344		761			794
INCOME BEFORE INCOME TAXES		25,867			11,466		68,420			34,797
INCOME TAX EXPENSE		546			663		2,013			2,338
NET INCOME	$	25,321		$	10,803	$	66,407		$	32,459
ALLOCATION OF NET INCOME:
PORTION APPLICABLE TO WARRIOR COAL LOSS PRIOR TO ITS ACQUISITION ON FEBRUARY 14, 2003	$	—		$	—	$	—		$	(666	)
PORTION APPLICABLE TO PARTNERS’ INTEREST		25,321			10,803		66,407			33,125
NET INCOME	$	25,321		$	10,803	$	66,407		$	32,459
GENERAL PARTNERS’ INTEREST IN NET INCOME (LOSS)	$	843		$	216	$	2,235		$	(3	)
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	24,478		$	10,587	$	64,172		$	32,462
BASIC NET INCOME PER LIMITED PARTNER UNIT	$	1.37		$	0.59	$	3.58		$	1.86
DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	1.33		$	0.57	$	3.48		$	1.80
DISTRIBUTION PAID PER COMMON AND SUBORDINATED UNIT	$	0.65		$	0.525	$	1.8375		$	1.575
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-BASIC		17,903,793			17,903,793		17,903,793			17,471,864
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-DILUTED		18,438,758			18,487,787		18,437,170			18,053,904

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2004			2003
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	125,904		$	62,491
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property, plant and equipment		(40,328	)		(34,190	)
Purchase of Warrior Coal		—			(12,661	)
Proceeds from sale of property, plant and equipment		461			413
Purchase of marketable securities		(4,969	)		(23,021	)
Proceeds from marketable securities		13,672			—
Proceeds from assumption of liability		2,112			—
Net cash used in investing activities		(29,052	)		(69,459	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from common unit offering to public		—			53,956
Cash contribution by General Partners		—			9
Payments on Warrior Coal revolving credit agreement balance		—			(17,000	)
Borrowings under revolving credit facility and working capital facilities		—			31,600
Payments under revolving credit facility and working capital facilities		—			(10,600	)
Payments on long-term debt		—			(31,250	)
Distributions to Partners		(34,165	)		(27,435	)
Net cash used in financing activities		(34,165	)		(720	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		62,687			(7,688	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		10,156			9,028
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	72,843		$	1,340
CASH PAID FOR:
Interest	$	15,093		$	15,803
Income taxes to taxing authorities	$	2,150		$	2,281

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND PRESENTATION

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

The accompanying condensed consolidated financial statements include the accounts and operations of the Partnership and present the financial position as of September 30, 2004 and December 31, 2003, the results of its operations for the three months and nine months ended September 30, 2004 and 2003, and cash flows for the nine months ended September 30, 2004 and 2003. All material intercompany transactions and accounts of the Partnership have been eliminated.

On February 14 and March 14, 2003, the Partnership issued 2,250,000 and 288,000 additional Common Units at a public offering price of $22.51 per unit and received net proceeds of $48.5 million and $6.2 million, respectively, before expenses of approximately $0.8 million, excluding underwriters fees. On November 15, 2003, 3,211,265 outstanding Subordinated Units were converted to Common Units in accordance with the Partnership’s Agreement. On November 2, 2004, the remaining 3,211,266 subordinated units converted to common units and the Partnership issued 231,126 additional common units pursuant to the Long-Term Incentive Plan (Note 8).

On February 14, 2003, the Partnership acquired Warrior Coal, LLC (“Warrior Coal”) (Note 3). Because the Warrior Coal acquisition was between entities under common control, the acquisition was recorded at historical cost in a manner similar to that used in a pooling of interests. Accordingly, the condensed consolidated financial statements and notes of the Partnership have been restated to reflect the combined historical results of operations, financial position and cash flows of the Partnership and Warrior Coal for the nine months ended September 30, 2003.

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

These condensed consolidated financial statements and notes are prepared pursuant to the rules and regulations of the Securities and Exchange Commission for interim reporting and should be read in conjunction with the consolidated financial statements and notes included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2003.

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

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provided for or covered under insurance, is not expected to have a material adverse effect on the Partnership’s business, financial position or results of operations. Nonetheless, these matters or estimates that are based on current facts and circumstances, if resolved in a manner different from the basis on which management has formed its opinion, could have a material adverse effect on the Partnership’s financial position or results of operations.

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

The appeal periods for the scalp rock permit and the two water discharge permits related to the operation of the scalp rock disposal facility and underground mine have lapsed without any appeal being filed. Two appeals of the underground mining permit were filed on June 11 and 16, 2004, respectively. The West Virginia Surface Mine Board (“SMB”) consolidated the appeals and held an administrative initial hearing on October 19 and 20, 2004 with a continuance of the administrative hearing scheduled for December 7 and 8, 2004. Decisions are normally rendered within several weeks after an administrative hearing has been concluded. Management believes the WVDEP’s approval of the permit applications will be upheld by the SMB.

See also Note 8 regarding contract dispute with ICG, LLC (“ICG”).

3. ACQUISITIONS

Warrior Coal

On February 14, 2003, the Partnership acquired Warrior Coal pursuant to the terms of an Amended and Restated Put and Call Option Agreement (“Put/Call Agreement”) with ARH Warrior Holdings, Inc. (“ARH Warrior”), a subsidiary of ARH. The Partnership acquired Warrior Coal for approximately $12.7 million and paid Warrior Coal’s borrowings of $17.0 million under a revolving credit agreement between Alliance Resource GP, LLC (the “Special GP”), a subsidiary of ARH, and Warrior Coal. Because the Warrior Coal acquisition was between entities under common control, the acquisition is accounted for at historical cost in a manner similar to that used in a pooling of interests. The Partnership financed the transaction with a portion of the net proceeds of the public offering of 2,538,000 Common Units (Note 1) in February and March 2003.

Under the terms of the Put/Call Agreement, the Partnership assumed certain other obligations, including a mineral lease and sublease with SGP Land, LLC, an affiliate of ARH Warrior, covering coal reserves that have been and will continue to be mined by Warrior Coal. The terms and conditions of the mineral lease and sublease were not changed as a result of the acquisition.

Lodestar

On July 15, 2003, Hopkins County Coal, LLC (“Hopkins County Coal”) executed an Asset Purchase Agreement with Lodestar Energy, Inc. (“Lodestar”), a coal company operating in Chapter 7

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bankruptcy proceedings. Concurrently, Hopkins County Coal entered into various other agreements (collectively, the Asset Purchase Agreement and the various other agreements are referred to as the “Lodestar Agreements”) with several parties, including the Kentucky Environmental and Public Protection Cabinet (“Cabinet”) and Frontier Insurance Company (“Frontier”). Closing of the Lodestar Agreements was subject to the resolution of numerous contingencies and/or conditions. Under the terms of the relevant Lodestar Agreements, Hopkins County Coal principally acquired a mining pit, created by Lodestar’s mining activities. The mining pit will be used for refuse disposal by the Partnership’s Webster County Coal, LLC’s Dotiki mine. The purchase price included a nominal monetary amount and the assumption of remedial reclamation activities under the various mining permits acquired by Hopkins County Coal from Lodestar. The Cabinet accepted these remedial activities in lieu of certain solid waste closure requirements applicable to residual landfills. Hopkins County Coal also received $2.1 million from Frontier in exchange for the assumption of the remedial activities associated with the mining pit. As a result of closing the Lodestar Agreements on June 2, 2004, Hopkins County Coal recorded the fair value of the asset retirement obligation of approximately $4.1 million with a corresponding asset that was reduced by the $2.1 million of cash received.

4. DOTIKI FIRE INCIDENT

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

On September 10, 2004, the Partnership filed a third and final proof of loss with the applicable insurance underwriters reflecting a settlement (the “Settlement”) of all expenses, losses and claims incurred by Webster County Coal and other affiliates arising from or in connection with the Dotiki Fire Incident (the “Insurance Claim”) in the aggregate amount of $27.0 million, inclusive of a $1.0 million self-retention, a $2.5 million deductible (collectively, the “Insurance Deductibles”) and 10% co-insurance (the “Co-Insurance”). The Insurance Deductibles and Co-Insurance have been allocated on a pro-rata basis to each of the three areas of insurance recoveries discussed below. Previously, Webster County Coal had received two partial advance payments of $4.5 million and $3.6 million, respectively, net of the Insurance Deductibles and Co-Insurance. The accounting for these two net partial advance payments in the aggregate amount of $8.1 million and the final net payment of $13.05 million, exclusive of the Insurance Deductible and Co-Insurance, are subject to the accounting methodology described below. Specifically, the Partnership has evaluated and accounted for the insurance recoveries in the following areas:

1. Expenses incurred as a result of the fire – The Partnership incurred extra expenses, expediting expenses, and other costs associated with extinguishing the fire in an aggregate amount of approximately $7.1 million. With application of $5.6 million of the insurance recovery proceeds, the Partnership has recorded net expenses of approximately $1.5 million.

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2. Damage to Dotiki mine property – The Partnership incurred damage to Dotiki’s mine property (exclusive of any amounts relating to matters discussed in 1. above) of approximately $1.2 million, which property had a net book value of $138,000. This net book amount was written off in the first quarter of 2004, and a corresponding amount was recorded in the first quarter of 2004 as an estimated insurance recovery. Based on discussions with the underwriters culminating in the Settlement, the Partnership recorded a net gain of approximately $785,000, reflecting the amount that the allocated insurance proceeds exceeded the net book value of the damaged property.

3. Dotiki mine business interruption costs and extra expense – Based on the negotiations with the underwriters leading to the Settlement, the Partnership recorded a net gain of approximately $14.4 million for the recovery of business interruption costs and extra expenses stemming from the Dotiki Fire Incident. This net gain amount reflects an offset of approximately $200,000 for professional services expenses incurred in resolving the business interruption portion of the settlement.

Pursuant to the accounting methodology described above, the Partnership (a) has recorded, as an offset to operating expenses, approximately $2.9 million, $0.2 million, and $2.8 million, during the first, second, and third quarters of 2004, respectively, and (b) in the third quarter of 2004, recorded a combined net gain of approximately $15.2 million for damage to property destroyed, interruption of business operations (including profit recovery), and extra expenses incurred to minimize the period and total cost of disruption to operations.

5. NET INCOME PER LIMITED PARTNER UNIT

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Net income	$	25,321		$	10,803		$	66,407		$	32,459
Adjustments:
Managing general partner’s incentive distributions		(343	)		—			(925	)		—
General partners’ 2% equity ownership		(500	)		(216	)		(1,310	)		(663	)
Portion applicable to Warrior Coal loss prior to its acquisition on February 14, 2003		—			—			—			666
Limited partners’ interest in net income	$	24,478		$	10,587		$	64,172		$	32,462
Weighted average limited partner units – basic		17,904			17,904			17,904			17,472
Basic net income per limited partner unit	$	1.37		$	0.59		$	3.58		$	1.86
Weighted average limited partner units – basic		17,904			17,904			17,904			17,472
Units contingently issuable:
Restricted units for Long-Term Incentive Plan		472			527			472			527
Directors’ compensation units deferred		17			17			16			16
Supplemental Executive Retirement Plan		46			40			45			39
Weighted average limited partner units, assuming dilutive effect of restricted units		18,439			18,488			18,437			18,054
Diluted net income per limited partner unit	$	1.33		$	0.57		$	3.48		$	1.80

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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 for incentive distributions, if any, to the Partnership’s managing general partner (the “Managing GP”), the holder of the incentive distribution rights pursuant to the Partnership Agreement, which are declared and paid following the close of each quarter. Warrior Coal’s loss prior to its acquisition on February 14, 2003 was allocated to the general partners.

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

6. RESTRICTED UNIT-BASED COMPENSATION

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Net income, as reported	$	25,321		$	10,803		$	66,407		$	32,459
Add: compensation expense related to Long-Term Incentive Plan units included in reported net income		6,662			1,850			15,385			4,591
Deduct: compensation expense related to Long-Term Incentive Plan units determined under fair value method for all awards		(1,122	)		(879	)		(3,343	)		(2,615	)
Net income, pro forma	$	30,861		$	11,774		$	78,449		$	34,435
General partners’ interest in net income, pro forma	$	953		$	235		$	2,475		$	36
Limited partners’ interest in net income, pro forma	$	29,908		$	11,539		$	75,974		$	34,399
Earnings per limited partner unit:
Basic, as reported	$	1.37		$	0.59		$	3.58		$	1.86
Basic, pro forma	$	1.67		$	0.64		$	4.24		$	1.97
Diluted, as reported	$	1.33		$	0.57		$	3.48		$	1.80
Diluted, pro forma	$	1.62		$	0.62		$	4.12		$	1.91

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The total accrued liability associated with the Long-Term Incentive Plan as of September 30, 2004 and December 31, 2003 was $27,878,000 and $12,493,000, respectively, and is included in the current and long-term due to affiliates liability in the condensed consolidated balance sheet.

7. RECENT ACCOUNTING PRONOUNCEMENTS

Consistent with other extractive industry entities, the Partnership has historically classified leased coal interests and advance royalties as tangible assets, which is consistent with the classification of owned coal due to the similar rights of the leaseholder. SFAS No. 141, “Business Combinations,” identifies mineral rights as an example of a contract-based intangible asset that should be considered for separate classification as the result of a business combination. Due to the potential for inconsistencies in applying the provisions of SFAS No. 141 and SFAS No. 142, “Goodwill and Other Tangible Assets,” in the extractive industries as they relate to mineral interests controlled by other than fee ownership, the Emerging Issues Task Force (“EITF”) established a Mining Industry Working Group to address this issue. During March 2004, the EITF reached a consensus regarding classification of leased coal interests and advance royalties as tangible assets. On April 30, 2004, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) Nos. 141-1 and 142-1, “Interaction of FASB Statements No. 141, Business Combination, and No. 142 Goodwill and Other Intangible Assets,” and EITF Issue No. 04-02, “Whether Mineral Rights Are Tangible or Intangible Assets,” which amends SFAS Nos. 141 and 142 to state that certain use rights may have characteristics of assets other than intangible assets. Accordingly, use rights should be accounted for based on their substance. The guidance in these FSPs is to be applied to the first reporting period beginning after April 29, 2004. The Partnership does not believe these FSPs result in a re-characterization of its related assets, which have historically been classified as tangible.

8. SUBSEQUENT EVENTS

On October 22, 2004, the Partnership declared a quarterly distribution, for the quarterly period ended September 30, 2004, of $0.65 per unit, totaling approximately $12.2 million (which includes the Managing GP’s portion of incentive distributions), on all of its Common and Subordinated Units outstanding, payable on November 12, 2004, to all unitholders of record as of November 1, 2004.

As of September 30, 2004, the Partnership satisfied the final conversion financial tests for converting the remaining Subordinated Units into Common Units as provided for under applicable provisions in the Partnership Agreement. On October 21, 2004, the Board of Directors (and its Conflicts Committee) of the Managing GP, approved management’s determination that such final conversion financial tests were satisfied as of September 30, 2004. As a result, the remaining outstanding Subordinated Units (i.e., 3,211,266 Subordinated Units) held by the Special GP converted into Common Units on November 2, 2004. As of November 2, 2004, the Special GP owned 7,655,311 of the Partnership’s outstanding Common Units. Pursuant to the Partnership’s Long-Term Incentive Plan, on November 2, 2004, 385,210 restricted units previously awarded to certain members of management, employees, and directors vested. As a result of this vesting, the Partnership issued 231,126 Common Units. The remaining units were settled in cash to satisfy individual tax obligations.

On October 21, 2004, the Partnership announced an agreement to enter into two separate coal leases, which cumulatively will increase the Partnership’s coal reserve holdings by 25%. The Elk Creek reserves (“Elk Creek”) are located in Hopkins County, Kentucky, and the Tunnel Ridge reserves (“Tunnel Ridge”) are located in Ohio County, West Virginia and Washington County, Pennsylvania. These leases are estimated to contain approximately 100 million tons of high-sulfur coal reserves. The lessor for both leases is the Special GP. The Partnership also announced plans to immediately begin the development process for these properties, which includes obtaining the necessary mining permits and securing

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sufficient coal sales commitments to justify the capital investment needed to bring these properties into production. Definitive development commitments for Elk Creek and Tunnel Ridge reserves are dependent upon final approval by the Board of Directors of the Partnership’s Managing GP.

The Elk Creek reserve area encompasses approximately 9,000 acres and is contiguous to the Partnership’s Hopkins County Coal complex. The Elk Creek coal reserves are currently estimated to include approximately 30 million tons of high-sulfur coal. The Elk Creek mine will be an underground mining complex, mining the West Kentucky No. 9 and No. 11 coal seams, utilizing continuous mining units employing room-and-pillar mining techniques. The mine intends to utilize the existing coal handling and other surface facilities owned by Hopkins County Coal. It is anticipated that the Elk Creek complex will utilize as many as 250 employees and produce up to 3.2 million tons of coal annually. The Partnership is estimating total capital expenditures to develop Elk Creek to be approximately $60 million invested over a two-year period. Coal supply commitments are currently being pursued. Construction of the Elk Creek mining complex may begin as early as the second quarter of 2005. The Partnership expects to fund these capital expenditures with available cash and marketable securities on hand, future cash generated from operations and borrowings available under the revolving credit facility.

In December 2000, Hopkins County Coal entered into an option agreement to lease and/or sublease the Elk Creek reserves from the Partnership’s Special GP. Under the terms of the option to lease and sublease, Hopkins County Coal paid an option fee of $645,000 during the year ended December 31, 2000, and paid option fees of $684,000 during the years ended December 31, 2001 and 2002. The 2003 option fee of $684,000 was paid in January 2004. Upon exercise of the option to lease or sublease, Hopkins County Coal is obligated to make an additional six annual advance minimum royalty payments of $684,000 per year, which royalty is fully recoupable against earned royalties. The earned royalty rate under the lease and or sublease is $0.25 per ton.

The Partnership will acquire 100% of the limited liability company member interests of Tunnel Ridge, LLC from Alliance Resource Holdings, Inc., a company owned by management of the Partnership. Tunnel Ridge, LLC controls through a coal lease agreement with the Special GP an estimated 70 million tons of high-sulfur coal in the Pittsburgh No. 8 coal seam. The Tunnel Ridge reserve area encompasses approximately 50,571 acres of land located in Ohio County, West Virginia and Washington County, Pennsylvania. Under the terms of the coal lease, beginning on January 1, 2005, Tunnel Ridge, LLC shall pay the Special GP an advance minimum royalty of $3.0 million per year, which advance royalty payments will be fully recoupable against earned royalties. The earned royalty rate under the coal lease is the greater of $0.75 per ton or 3.0% of the per ton gross sales price f.o.b. barge. The term of the coal lease is the earlier of 30 years or until exhaustion of all mineable and merchantable coal with termination rights after the initial four years of the coal lease.

Tunnel Ridge, LLC also controls, under a separate lease agreement with the Special GP, the rights to approximately 900 acres of surface land and other tangible assets. Under the terms of the lease agreement, Tunnel Ridge, LLC shall remit to the Special GP an annual lease payment of $240,000 beginning January 1, 2005. The lease agreement has an initial term of four years, which term may be extended by Tunnel Ridge, LLC, at the same annual lease payment rate, to be consistent with the coal lease.

The Partnership expects to begin immediately the permitting process of the Tunnel Ridge Reserves. It is anticipated that the Tunnel Ridge operation will utilize a longwall miner for the majority of its coal extraction as well as continuous mining units used to prepare the mine for future longwall mining. The Partnership estimates that the Tunnel Ridge operation will be designed to produce up to six million tons of coal annually. The Partnership is hopeful production from Tunnel Ridge can begin in the 2008 time frame. It is anticipated that the Tunnel Ridge complex will employ as many as 300 employees. The Partnership is estimating total capital expenditures required to develop Tunnel Ridge to be

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approximately $200 million over a five-year period. The Partnership currently expects to fund these capital expenditures with available cash and marketable securities, future cash generated from operations and borrowings available under the revolving credit facility.

The Elk Creek and Tunnel Ridge transactions described above are related-party transactions and, as such, were reviewed by the Board of Directors and Conflicts Committee of the Partnership’s Managing GP. Based upon this review, it was determined that these transactions reflect market-clearing terms and conditions customary in the coal industry. As a result, the Board of Directors and Conflicts Committee of the Partnership’s Managing GP approved the Elk Creek and Tunnel Ridge transactions as fair and reasonable to the Partnership and its limited partners.

On October 12, 2004, Pontiki Coal, LLC (“Pontiki”) was served with a complaint from ICG alleging a breach of contract and seeking declaratory relief to determine the parties’ rights under a coal sales agreement between Horizon Natural Resource Sales Company (“Horizon Sales”), as buyer, and Pontiki Coal Corporation, as seller, dated October 3, 1998, as amended on February 28, 2001 (the “Agreement”). ICG has represented that it acquired the rights and assumed the liabilities of the 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. Pontiki is the successor-in-interest of Pontiki Coal Corporation as a result of a merger completed on August 4, 1999.

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 Agreement have not been 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 Agreement. This litigation is in the preliminary stage, but the Partnership does not believe that it 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.

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

SUMMARY

We reported record quarterly net income for the three months ended September 30, 2004 (the 2004 Quarter) of $25.3 million, an increase of 134.4% over the three months ended September 30, 2003 (the 2003 Quarter). The 2004 Quarter benefited from the final settlement of an insurance claim with our insurance underwriters relating to the Dotiki mine fire earlier this year. See “Dotiki Fire Incident” below. Results for the 2004 Quarter were negatively impacted by the buy-out of several coal sales contracts, which will allow us to take advantage of anticipated higher spot coal prices in 2005. We continue to benefit from favorable coal markets despite increases in material and supply costs.

We have contractual commitments for all of our remaining 2004 production. For our estimated 2005 production of 22.9 million tons, approximately 95% is committed under existing coal sales agreements, and approximately 29% is subject to market price negotiations for existing contracts as well as anticipated new coal supply agreements.

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In response to demand in the Illinois Basin, we have entered into a coal supply arrangement with a third-party supplier to purchase 25,000 tons per month through December 31, 2004, increasing to 40,000 tons per month beginning January 1, 2005 and continuing through June 30, 2007.

RESULTS OF OPERATIONS

Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003

	September 30,				September 30,
	2004		2003		2004		2003
	(in thousands)				(per ton sold)
Tons sold		5,111		5,181		N/A		N/A
Tons produced		4,886		4,729		N/A		N/A
Coal sales	$	146,350	$	131,131	$	28.63	$	25.31
Operating expenses and outside purchases	$	111,329	$	102,308	$	21.78	$	19.75

Coal sales. Coal sales for the 2004 Quarter increased 11.6% to $146.4 million from $131.1 million for the 2003 Quarter. The increase of $15.3 million reflects higher prices on long-term coal sales agreements and significantly higher prices on short-term coal sales agreements into the export and Central Appalachia coal markets. Higher prices on long-term contracts reflect a stronger market in the second half of 2003 when contracts were entered into for shipments in 2004 compared to the market in the second half of 2002 when contracts were entered into for shipments in 2003. The export market opportunities for the U.S. coal industry were generally attributable to strong economic expansion in China. The increase in Central Appalachia spot market pricing was primarily attributable to a combination of the diversion of coal production from domestic markets to export markets and a decline in region-wide production. Tons sold were comparable for the 2004 and 2003 Quarter at 5.1 million and 5.2 million, respectively. Tons produced increased 3.3% to 4.9 million tons for the 2004 Quarter from 4.7 million for the 2003 Quarter.

Operating expenses. Operating expenses increased 10.6% to $108.9 million for the 2004 Quarter from $98.5 million for the 2003 Quarter. The increase of $10.4 million resulted from the $3.2 million buy-out expense of several coal contracts which will allow us to take advantage of anticipated higher spot coal prices in 2005 and higher operating expenses due to increased coal production volumes, increased materials and supply costs (particularly fuel, power and steel), sales-related expenses and maintenance expenses. Partially offsetting these increases was a reduction in operating expenses of approximately $2.8 million due to the final settlement of insurance claims attributable to the Dotiki mine fire. See “Dotiki Fire Incident” below.

General and administrative. General and administrative expenses increased to $12.7 million for the 2004 Quarter compared to $6.5 million for the 2003 Quarter. The increase of $6.2 million was primarily attributable to higher incentive compensation expense, which increased approximately $5.8 million. These incentive compensation plans include the Long-Term Incentive Plan, which is a restricted unit program and is impacted by the increased market value of our common units, which closed at $55.67 on September 30, 2004, and the Short-Term Incentive Plan, which provides our employees an opportunity to receive additional compensation based upon our financial performance.

Other sales and operating revenues. Other sales and operating revenues were comparable for each of the 2004 and 2003 Quarters at $5.4 million, for each period.

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Outside purchases. Outside purchases decreased to $2.4 million for the 2004 Quarter compared to $3.8 million for the 2003 Quarter. The decrease of $1.4 million was primarily attributable to a decrease in the domestic brokerage market partially offset by an increase in outside purchases at our Illinois Basin operations from a third-party supplier.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $13.6 million for the 2004 Quarter compared to $12.6 million for the 2003 Quarter. The increase of $1.0 million was primarily the result of additional depreciation expense associated with increased capital expenditures and infrastructure investments over the last few years, which have increased our production capacity.

Interest expense. Interest expense was comparable for the 2004 and 2003 Quarters at $3.7 million and $4.1 million, respectively. We had no borrowings under the credit facility during the 2004 Quarter.

Transportation revenues and expenses. Transportation revenues and expenses increased to $6.5 million for the 2004 Quarter compared to $5.2 million for the 2003 Quarter. The increase of $1.3 million was primarily attributable to higher sales volumes and increased shipments to customers with higher transportation costs.

Income before income taxes. Income before income taxes increased to $25.9 million for the 2004 Quarter from $11.5 million for the 2003 Quarter. The increase of $14.4 million is primarily attributable to the 2004 Quarter benefit of the final settlement of an insurance claim attributable to the Dotiki mine fire and continued higher prices on both long-term coal sales agreements and short-term sales agreements in the export and Central Appalachia coal markets. See “Dotiki Fire Incident” below. These benefits were offset by the higher production costs and increased general and administrative expense discussed above.

Income tax expense. Income tax expense was comparable for each of the 2004 and 2003 Quarters at $0.5 million and $0.7 million, respectively.

Nine Months Ended September 30, 2004 compared to Nine Months Ended September 30, 2003

We reported record net income for the nine months ended September 30, 2004 (the 2004 Period) of $66.4 million, an increase of 104.6% over the nine months ended September 30, 2003 (the 2003 Period). The continuing strength in both the domestic and international coal markets continue to favorably impact our financial results for the 2004 Period. The 2004 Period benefited from the final settlement of an insurance claim with our insurance underwriters relating to the Dotiki mine fire earlier this year. See “Dotiki Fire Incident” below.

	September 30,				September 30,
	2004		2003		2004		2003
	(in thousands)				(per ton sold)
Tons sold		15,417		14,386		N/A		N/A
Tons produced		15,183		14,362		N/A		N/A
Coal sales	$	440,214	$	368,170	$	28.55	$	25.59
Operating expenses and outside purchases	$	320,378	$	281,382	$	20.78	$	19.56

Coal sales. Coal sales for the 2004 Period increased 19.6% to $440.2 million from $368.2 million for the 2003 Period. The increase of $72.0 million reflects higher prices on long-term coal sales

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agreements and the sale of additional production at significantly higher prices on short-term coal sales agreements into the export and Central Appalachia coal markets. Higher prices on long-term contracts reflect a stronger market in the second half of 2003 when contracts were entered into for shipments in 2004 compared to the market in the second half of 2002 when contracts were entered into for shipments in 2003. The export market opportunities for the U.S. coal industry were attributable generally to the strong economic expansion in China. The increase in Central Appalachia spot market pricing was attributable primarily to a combination of the diversion of coal production from domestic markets to export markets and a decline in region-wide production. Coal sales further benefited by record year-to-date tons sold. Tons sold increased 7.2% to 15.4 million for the 2004 Period from 14.4 million for the 2003 Period. Tons produced increased 5.7% to 15.2 million tons for the 2004 Period from 14.4 million for the 2003 Period.

Operating expenses. Operating expenses increased 14.5% to $316.1 million for the 2004 Period from $276.1 million for the 2003 Period. The increase of $40.0 million primarily resulted from higher operating expenses associated with additional sales of 1.0 million tons, increased coal production volumes, increased materials and supply costs (particularly fuel, power and steel), sales related expenses and maintenance expenses. Additionally the 2004 Period includes a $3.2 million buy-out expense of several coal contracts which will allow us to take advantage of anticipated higher spot coal prices in 2005 and $1.5 million of net out-of-pocket expenses related to the Dotiki Fire. See “Dotiki Fire Incident” below.

General and administrative. General and administrative expenses increased to $34.3 million for the 2004 Period compared to $18.8 million for the 2003 Period. The increase of $15.5 million was attributable primarily to higher incentive compensation expense, which increased approximately $14.4 million. The incentive compensation plans include the Long-Term Incentive Plan, which is a restricted unit program and is impacted by the increased market value of our common units, which closed at $55.67 on September 30, 2004, and the Short-Term Incentive Plan, which provides our employees an opportunity to receive additional compensation based upon our financial performance.

Other sales and operating revenues. Other sales and operating revenues were comparable for the 2004 and 2003 Quarters at $18.1 million and $17.4 million, respectively.

Outside purchases. Outside purchases decreased to $4.3 million for the 2004 Period compared to $5.2 million for the 2003 Period. The decrease of $0.9 million was primarily attributable to a decrease in the domestic brokerage market partially offset by an increase in outside purchases at our East Kentucky and Illinois Basin operations.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expenses increased to $39.8 million for the 2004 Period compared to $39.3 million for the 2003 Period. The increase of $0.5 million was primarily the result of additional depreciation expense associated with increased capital expenditures and infrastructure investments over the last few years, which have increased our production capacity. This increase was partially offset by a $2.9 million decrease in depreciation attributable to the idling of Hopkins County Coal in June 2003

Interest expense. Interest expense decreased to $11.4 million for the 2004 Period compared to $12.0 million for the 2004 Period. The decrease of $0.6 million was attributable to reduced interest expense associated with the revolving credit facility. We have had no borrowings under the credit facility during the 2004 Period.

Transportation revenues and expenses. Transportation revenues increased to $20.4 million for the 2004 Period from $14.6 million for the 2003 Period. The increase of $5.8 million was primarily attributable to higher sales volumes and increased shipments to customers with higher transportation costs.

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Income before income taxes. Income before income taxes increased to $68.4 million for the 2004 Period from $34.8 million for the 2003 Period. The increase of $33.6 million is primarily attributable to higher sales prices, reflecting the continued strengthening of domestic and international coal markets, partially offset by higher production costs and increased general and administrative expense associated with higher incentive compensation expense. Proceeds from the final settlement of the Dotiki Fire Incident insurance claims also benefited the 2004 Period. See “Dotiki Fire Incident” below.

Income tax expense. Income expense was comparable for each of the 2004 and 2003 Periods at $2.0 million and $2.3 million, respectively.

Dotiki Fire Incident

On February 11, 2004, Webster County Coal, LLC’s (Webster County Coal) Dotiki mine was temporarily idled for a period of twenty-seven calendar days following the occurrence of a mine fire that originated with a diesel supply tractor (the Dotiki Fire Incident). As a result of the firefighting efforts of the Mine Safety and Health Administration, Kentucky Department of Mines and Minerals, and Webster County Coal personnel, Dotiki successfully extinguished the fire and totally isolated the affected area of the mine behind permanent barriers. Initial production resumed on March 8, 2004. We have commercial property insurance that provides 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 (the Settlement) of all expenses, losses and claims incurred by Webster County Coal and other affiliates arising from or in connection with the Dotiki Fire Incident (the Insurance Claim) in the aggregate amount of $27.0 million, inclusive of a $1.0 million self-retention, a $2.5 million deductible (collectively, the Insurance Deductibles) and 10% co-insurance (the Co-Insurance). The Insurance Deductibles and Co-Insurance have been allocated on a pro-rata basis to each of the three areas of insurance recoveries discussed below. Previously, Webster County Coal had received two partial advance payments of $4.5 million and $3.6 million, respectively, net of the Insurance Deductibles and Co-Insurance. The accounting for these two net partial advance payments in the aggregate amount of $8.1 million and the final net payment of $13.05 million, exclusive of the Insurance Deductible and Co-Insurance, are subject to the accounting methodology described below. Specifically, we have evaluated and accounted for the insurance recoveries in the following areas:

1. Expenses incurred as a result of the fire – we incurred extra expenses, expediting expenses, and other costs associated with extinguishing the fire in an aggregate amount of approximately $7.1 million. With application of $5.6 million of the insurance recovery proceeds, we have recorded net expenses of approximately $1.5 million.

2. Damage to Dotiki mine property – we incurred damage to Dotiki’s mine property (exclusive of any amounts relating to matters discussed in 1. above) of approximately $1.2 million, which property had a net book value of $138,000. This net book amount was written off in the first quarter of 2004, and a corresponding amount was recorded in the first quarter of 2004 as an estimated insurance recovery. Based on discussions with the underwriters culminating in the Settlement, we recorded a net gain of approximately $785,000, reflecting the amount that the allocated insurance proceeds exceeded the net book value of the damaged property.

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3. Dotiki mine business interruption costs and extra expense – Based on the negotiations with the underwriters leading to the Settlement, we recorded a net gain of approximately $14.4 million for the recovery of business interruption costs and extra expenses stemming from the Dotiki Fire Incident. This net gain amount reflects an offset of approximately $200,000 for professional services expenses incurred in resolving the business interruption portion of the settlement.

Pursuant to the accounting methodology described above, we (a) have recorded, as an offset to operating expenses, approximately $2.9 million, $0.2 million, and $2.8 million, during the first, second, and third quarters of 2004, respectively, and (b) in the third quarter of 2004, recorded a combined net gain of approximately $15.2 million for damage to property destroyed, interruption of business operations (including profit recovery), and extra expenses incurred to minimize the period and total cost of disruption to operations.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Cash provided by operating activities was $125.9 million for the 2004 Period compared to $62.5 million for the 2003 Period. The increase in cash provided by operating activities was principally attributable to an increase in net income and a greater reduction in total working capital. Total working capital changes include an increase in the total accrued liability for the Long-Term Incentive Plan included in the current and long-term due to affiliates liability, increases in accounts payable due to timing differences and higher operating costs offset by a timing and sales driven increases in trade receivables.

Net cash used in investing activities was $29.1 million for the 2004 Period compared to $69.5 million for the 2003 Period. The decrease is primarily attributable to the proceeds from marketable securities, net of purchases during the 2004 Period offset by net purchases of marketable securities which occurred during the 2003 Period. The decrease was further impacted by the Warrior Coal acquisition during the 2003 Period offset by an increase in capital expenditures associated with Dotiki expanding its preparation plant and adding two continuous miners.

Net cash used in financing activities was $34.2 million for the 2004 Period compared to $0.7 million for the 2003 Period. The increase is primarily attributable to the proceeds received from a common unit offering which occurred during the 2003 Period offset by the repayment of Warrior Coal’s revolving credit agreement balance during the 2003 Period and increased distributions to partners in the 2004 Period.

Capital Expenditures

Capital expenditures decreased to $40.3 million in the 2004 Period from $46.9 million in the 2003 Period, which includes the acquisition of Warrior Coal. See discussion of “Cash Flows” above concerning the decrease in capital expenditures.

Insurance

During September 2004, we completed our annual property and casualty insurance renewal. As a result, we will continue to retain a 10% participating interest along with our insurance carriers in the commercial property program. The aggregate maximum limit in the commercial property program is $75

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million per occurrence of which we would be responsible for a maximum amount of $7.5 million for each occurrence, excluding a $3.5 million deductible. As a result of the renewal for comparable levels of coverage, premiums for our property and casualty insurance programs increased by approximately 14.9%. In our history we have had one material insurance claim. See. “Dotiki Fire Incident” above. 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 and results of operations.

Notes Offering and Credit Facility

Alliance Resource Operating Partners, L.P., our intermediate partnership, has $180 million principal amount of 8.31% senior notes due August 20, 2014, payable in ten equal annual installments of $18 million beginning in August 2005 with interest payable semiannually (the Senior Notes). On August 22, 2003, our intermediate partnership completed a new $85 million revolving credit facility (the Credit Facility), which expires September 30, 2006. The Credit Facility replaced a $100 million credit facility that would have expired August 2004. We paid in full all amounts outstanding under the $100 million credit facility with borrowings of $20 million under the new Credit Facility. The interest rate on the Credit Facility is based on either (i) the London Interbank Offered Rate or (ii) the “Base Rate”, which is equal to the greater of the JPMorgan Chase Prime Rate or the Federal Funds Rate plus 1/2 of 1%, plus, in either case, an applicable margin. We incurred certain costs totaling $1.2 million associated with the Credit Facility. These costs have been deferred and are being amortized as a component of interest expense over the term of the Credit Facility. We had no borrowings outstanding under the Credit Facility at September 30, 2004. 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, 2004, 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. We were in compliance with the covenants of both the Credit Facility and Senior Notes at September 30, 2004.

We have previously entered into and have maintained agreements with two banks to provide additional letters of credit in an aggregate amount of $25.0 million to maintain surety bonds to secure our obligations for reclamation liabilities and workers’ compensation benefits. At September 30, 2004, we had $22.6 million in letters of credit outstanding under these agreements. Our special general partner guarantees these outstanding letters of credit.

Conversion of Subordinated Units

As of September 30, 2004, we satisfied the final conversion financial tests for converting the remaining subordinated units into common units as provided for under applicable provisions in the Partnership Agreement. On October 21, 2004, our board of directors (and its conflicts committee) of our managing general partner approved management’s determination that such final conversion financial tests were satisfied as of September 30, 2004. As a result, the remaining outstanding subordinated units (i.e., 3,211,266 subordinated units) held by our special general partner were converted into common units on November 2, 2004.

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Related Party Transactions

In February 2003, we acquired Warrior Coal from an affiliate, ARH Warrior Holdings, Inc. (ARH Warrior Holdings), in accordance with the terms of an Amended and Restated Put and Call Option Agreement. We paid $12.7 million to ARH Warrior Holdings and repaid Warrior Coal’s borrowings of $17.0 million under a revolving credit agreement between our special general partner and Warrior Coal. Please see “Item 1. Financial Statements – Note 3, Warrior Coal Acquisition.”

We have continuing related party transactions with our managing general partner and our special general partner, including our special general partner’s affiliates. These related party transactions relate principally to the provision of administrative services by our managing general partner, mineral and equipment leases with our special general partner and its affiliates, and guarantees from our special general partner for letters of credit.

Please read our Annual Report on Form 10-K for the year ended December 31, 2003, “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.

Elk Creek – Tunnel Ridge

On October 21, 2004, we announced an agreement to enter into two separate coal leases, which cumulatively will increase our coal reserve holdings by 25%. The Elk Creek reserves (Elk Creek) are located in Hopkins County, Kentucky, and the Tunnel Ridge reserves (Tunnel Ridge) are located in Ohio County, West Virginia and Washington County, Pennsylvania. These leases are estimated to contain approximately 100 million tons of high-sulfur coal reserves. The lessor for both leases is our special general partner. We also announced plans to immediately begin the development process for these properties, which includes obtaining the necessary mining permits and securing sufficient coal sales commitments to justify the capital investment needed to bring these properties into production. Definitive development commitments for Elk Creek and Tunnel Ridge reserves are dependent upon final approval by the board of directors of our managing general partner.

The Elk Creek reserve area encompasses approximately 9,000 acres and is contiguous to our Hopkins County Coal complex. The Elk Creek coal reserves are currently estimated to include approximately 30 million tons of high-sulfur coal. The Elk Creek mine will be an underground mining complex, mining the West Kentucky No. 9 and No. 11 coal seams, utilizing continuous mining units employing room-and-pillar mining techniques. We intend to utilize the existing coal handling and other surface facilities owned by Hopkins County Coal. We anticipate that the Elk Creek complex will utilize as many as 250 employees and produce up to 3.2 million tons of coal annually. We estimate total capital expenditures to develop Elk Creek to be approximately $60 million invested over a two-year period. Coal supply commitments are currently being pursued. Construction of the Elk Creek mining complex may begin as early as the second quarter of 2005. We expect to fund these capital expenditures with available cash and marketable securities on hand, future cash generated from operations and borrowings available under our revolving credit facility.

In December 2000, Hopkins County Coal entered into an option agreement to lease and/or sublease the Elk Creek reserves from our Special General Partner. Under the terms of the option to lease and sublease, Hopkins County Coal paid an option fee of $645,000 during the year ended December 31, 2000, and paid option fees of $684,000 during the years ended December 31, 2001 and 2002. The 2003 option fee of $684,000 was paid in January 2004. Upon exercise of the option to lease or sublease, Hopkins County Coal is obligated to make an additional six annual advance minimum royalty payments of $684,000 per year, which royalty is fully recoupable against earned royalties. The earned royalty rate under the lease and or sublease is $0.25 per ton.

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We will acquire 100% of the limited liability company member interests of Tunnel Ridge, LLC from Alliance Resource Holdings, Inc., a company owned by our management. Tunnel Ridge, LLC controls through a coal lease agreement with the Special GP an estimated 70 million tons of high-sulfur coal in the Pittsburgh No. 8 coal seam. The Tunnel Ridge reserve area encompasses approximately 50,571 acres of land located in Ohio County, West Virginia and Washington County, Pennsylvania. Under the terms of the coal lease, beginning on January 1, 2005, Tunnel Ridge, LLC shall pay our special general partner an advance minimum royalty of $3.0 million per year, which advance royalty payments will be fully recoupable against earned royalties. The earned royalty rate under the coal lease is the greater of $0.75 per ton or 3.0% of the per ton gross sales price f.o.b. barge. The term of the coal lease is the earlier of 30 years or until exhaustion of all mineable and merchantable coal with termination rights after the initial four years of the coal lease.

Tunnel Ridge, LLC also controls, under a separate lease agreement with our special general partner, the rights to approximately 900 acres of surface land and other tangible assets. Under the terms of the lease agreement, Tunnel Ridge, LLC shall remit to our special general partner an annual lease payment of $240,000 beginning January 1, 2005. The lease agreement has an initial term of four years, which term may be extended by Tunnel Ridge, LLC, at the same annual lease payment rate, to be consistent with the coal lease.

We expect to begin immediately the permitting process of the Tunnel Ridge Reserves. We anticipate that the Tunnel Ridge operation will utilize a longwall miner for the majority of its coal extraction as well as continuous mining units used to prepare the mine for future longwall mining. We estimate that the Tunnel Ridge operation will be designed to produce up to six million tons of coal annually. We are hopeful production from Tunnel Ridge can begin in the 2008 time frame. We anticipate that the Tunnel Ridge complex will employ as many as 300 employees. We estimate total capital expenditures required to develop Tunnel Ridge to be approximately $200 million over a five-year period. We currently expect to fund these capital expenditures with available cash and marketable securities, future cash generated from operations and borrowings available under our revolving credit facility.

The Elk Creek and Tunnel Ridge transactions described above are related-party transactions and, as such, were reviewed by the board of directors and conflicts committee of our managing general partner. Based upon this review, it was determined that these transactions reflect market-clearing terms and conditions customary in the coal industry. As a result, the board of directors and conflicts committee of our managing general partner approved the Elk Creek and Tunnel Ridge transactions as fair and reasonable to us.

Recent Accounting Pronouncements

Consistent with other extractive industry entities, we have historically classified leased coal interests and advance royalties as tangible assets, which is consistent with the classification of owned coal due to the similar rights of the leaseholder. Statement of Financial Accounting Standards (SFAS) No. 141, “Business Combinations,” identifies mineral rights as an example of a contract-based intangible asset that should be considered for separate classification as the result of a business combination. Due to the potential for inconsistencies in applying the provisions of SFAS No. 141 and SFAS No. 142, “Goodwill and Other Tangible Assets,” in the extractive industries as they relate to mineral interests controlled by other than fee ownership, the Emerging Issues Task Force (EITF) established a Mining Industry Working Group to address this issue. During March 2004, the EITF reached a consensus regarding classification of leased coal interests and advance royalties as tangible assets. On April 30, 2004, the Financial

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Accounting Standards Board (FASB) issued FASB Staff Position (FSP) Nos. 141-1 and 142-1, “Interaction of FASB Statements No. 141, Business Combination, and No. 142 Goodwill and Other Intangible Assets,” and EITF Issue No. 04-02, “Whether Mineral Rights Are Tangible or Intangible Assets,” which amends SFAS Nos. 141 and 142 to state that certain use rights may have characteristics of assets other than intangible assets. Accordingly, use rights should be accounted for based on their substance. The guidance in these FSPs is to be applied to the first reporting period beginning after April 29, 2004. We do not believe these FSPs result in a re-characterization of our related assets, which have historically been classified as tangible.

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, 2004.

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 2004 Period or at September 30, 2004.

As of September 30, 2004, the estimated fair value of the Senior Notes increased approximately $2.7 million due to lower market interest rates in 2004. 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, 2003.

ITEM 4. CONTROLS AND PROCEDURES

An evaluation was carried out by management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934). Based upon this evaluation, the chief executive officer and the chief financial officer concluded that the design and operation of these disclosure controls and procedures were effective as of the end of the period covered by this report. During the quarterly period ended September 30, 2004, there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Each of the chief executive officer and the chief financial officer of our managing general partner has furnished as Exhibit 32.1 and Exhibit 32.2, respectively, a certificate to the Securities and Exchange Commission as required by Section 906 of the Sarbanes-Oxley Act of 2002.

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FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements. These statements are based on our beliefs as well as assumptions made by, and information currently available to, us. When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast”, “may,” “project”, “will,” and similar expressions identify forward-looking statements. These statements reflect our current views with respect to future events and are subject to various risks, uncertainties and assumptions. Specific factors which could cause actual results to differ from those in the forward-looking statements, include:

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

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

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

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

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

• customer delays or defaults in making payments;

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

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

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

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

• greater than expected environmental regulation, costs and liabilities;

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

• risk of major mine-related accidents or interruptions;

• results of litigation;

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

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

If one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2003. 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.

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PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The information under “Contingencies” in Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements herein is hereby incorporated by reference. See also “Item 3. Legal Proceedings” in the Annual Report on Form 10-K for the year ended December 31, 2003.

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

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 8, 2004, 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 8, 2004, 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 8, 2004, 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 8, 2004, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 furnished herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, in Tulsa, Oklahoma, on November 8, 2004.

ALLIANCE RESOURCE PARTNERS, L.P.
By:	Alliance Resource Management GP, LLC
	its managing general partner
	/s/ Joseph W. Craft III
	Joseph W. Craft III
	President, Chief Executive
	Officer and Director
	/s/ Brian L. Cantrell
	Brian L. Cantrell
	Senior Vice President
	and Chief Financial Officer

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EXHIBIT INDEX

Exhibit No.	Description
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 8, 2004, 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 8, 2004, 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 8, 2004, 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 8, 2004, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 furnished herewith.

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