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, 2006

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

For the transition period from to

Commission File No.: 0-26823

ALLIANCE RESOURCE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware

73-1564280

(State or other jurisdiction of

incorporation or organization)

(IRS Employer

Identification No.)

1717 South Boulder Avenue, Suite 400, Tulsa, Oklahoma 74119

(Address of principal executive offices and zip code)

(918) 295-7600

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (check one)

Large Accelerated Filer x Accelerated Filer ¨ Non-Accelerated Filer ¨

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

As of November 7, 2006, 36,426,306 Common Units are outstanding.

TABLE OF CONTENTS


		Page
PART I

FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)	1

	ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

	CONDENSED CONSOLIDATED BALANCE SHEETS AS OF SEPTEMBER 30, 2006 AND DECEMBER 31, 2005	1

	CONDENSED CONSOLIDATED STATEMENTS OF INCOME FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2006 AND 2005	2

	CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2006 AND 2005	3

	NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	4

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	35

ITEM 4.	CONTROLS AND PROCEDURES	35

	FORWARD-LOOKING STATEMENTS	37

PART II

OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS	38

ITEM 1A.	RISK FACTORS	38

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	39

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	39

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	39

ITEM 5.	OTHER INFORMATION	39

ITEM 6.	EXHIBITS	40

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, 2006			December 31, 2005
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	36,447		$	32,054
Trade receivables, net		94,735			94,495
Other receivables		3,284			2,330
Due from affiliates		56			—
Marketable securities		155			49,242
Inventories		35,787			17,270
Advance royalties		2,952			2,952
Prepaid expenses and other assets		855			8,934

Total current assets		174,271			207,277

PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment at cost		776,300			635,086
Less accumulated depreciation, depletion and amortization		(374,839	)		(330,672	)

Total property, plant and equipment		401,461			304,414

OTHER ASSETS:
Advance royalties		22,842			16,328
Other long-term assets		5,801			4,668

Total other assets		28,643			20,996

TOTAL ASSETS	$	604,375		$	532,687

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	61,970		$	53,473
Due to affiliates		1,556			8,795
Accrued taxes other than income taxes		13,458			13,177
Accrued payroll and related expenses		16,267			12,466
Accrued pension benefit		5,500			7,588
Accrued interest		1,263			4,855
Workers’ compensation and pneumoconiosis benefits		7,593			7,740
Other current liabilities		12,179			5,120
Current maturities, long-term debt		18,000			18,000

Total current liabilities		137,786			131,214

LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities		126,000			144,000
Pneumoconiosis benefits		25,546			23,293
Workers’ compensation		36,509			30,050
Reclamation and mine closing		42,894			38,716
Due to affiliates		1,506			6,940
Minority interest		904			—
Other liabilities		7,091			2,697

Total long-term liabilities		240,450			245,696

Total liabilities		378,236			376,910

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:
Limited Partners - Common Unitholders 36,426,306 units outstanding		528,736			461,068
General Partners’ deficit		(295,644	)		(298,270	)
Unrealized loss on marketable securities		—			(68	)
Minimum pension liability		(6,953	)		(6,953	)

Total Partners’ capital		226,139			155,777

TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	604,375		$	532,687

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,
	2006			2005			2006			2005
SALES AND OPERATING REVENUES:
Coal sales	$	228,802		$	189,639		$	652,527		$	560,612
Transportation revenues		10,966			9,100			29,956			27,107
Other sales and operating revenues		4,972			8,304			21,881			23,667

Total revenues		244,740			207,043			704,364			611,386

EXPENSES:
Operating expenses		162,209			129,912			455,096			377,430
Transportation expenses		10,966			9,100			29,956			27,107
Outside purchases		6,020			3,472			14,251			10,981
General and administrative		7,391			12,812			21,640			29,067
Depreciation, depletion and amortization		17,273			13,798			48,283			40,822

Total operating expenses		203,859			169,094			569,226			485,407

INCOME FROM OPERATIONS		40,881			37,949			135,138			125,979
Interest expense (net of interest capitalized for the three and nine months ended September 30, 2006 of $462 and $1,153, respectively)		(2,870	)		(3,709	)		(9,458	)		(11,609	)
Interest income		712			868			2,525			1,924
Other income		216			90			684			314

INCOME BEFORE INCOME TAXES, CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND MINORITY INTEREST		38,939			35,198			128,889			116,608
INCOME TAX EXPENSE		352			717			1,658			2,256

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND MINORITY INTEREST		38,587			34,481			127,231			114,352
CUMULATIVE EFFECT OF ACCOUNTING CHANGE		—			—			112			—
MINORITY INTEREST		53			—			96			—

NET INCOME	$	38,640		$	34,481		$	127,439		$	114,352

GENERAL PARTNERS’ INTEREST IN NET INCOME	$	6,051		$	2,908		$	16,985		$	7,617

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	32,589		$	31,573		$	110,454		$	106,735

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.70		$	0.65		$	2.26		$	2.09

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.69		$	0.63		$	2.24		$	2.05

DISTRIBUTIONS PAID PER COMMON AND SUBORDINATED UNIT	$	0.50		$	0.41250		$	1.42		$	1.16250

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-BASIC		36,426,306			36,260,880			36,426,306			36,260,880

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-DILUTED		36,824,613			36,997,338			36,795,976			36,995,130

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,
	2006			2005
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	184,450		$	151,569

CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(141,963	)		(80,603	)
Changes in accounts payable and accrued liabilities		(1,198	)		1,630
Proceeds from sale of property, plant and equipment		599			198
Purchase of marketable securities		(19,188	)		(39,106	)
Proceeds from marketable securities		68,343			39,014
Payments for acquisition of business		(2,318	)		—

Net cash used in investing activities		(95,725	)		(78,867	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of long-term debt		(18,000	)		(18,000	)
Payment of debt issuance cost		(690	)		—
Equity contribution received by Mid-America Carbonates, LLC		1,000			—
Distributions to Partners		(66,642	)		(47,109	)

Net cash used in financing activities		(84,332	)		(65,109	)

NET CHANGE IN CASH AND CASH EQUIVALENTS		4,393			7,593

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		32,054			31,177

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	36,447		$	38,770

CASH PAID FOR:
Interest	$	13,711		$	15,160

Income taxes to taxing authorities	$	1,900		$	2,675

NON-CASH INVESTING ACTIVITY
Purchase of property, plant and equipment	$	8,166		$	5,415

See notes to condensed consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND PRESENTATION

Significant Relationships referenced in Notes to Condensed Consolidated Financial Statements

•

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

•

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

•

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

•

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

•

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

•

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

•

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

Organization and Formation

We are a Delaware limited partnership listed on the NASDAQ Global Select Market under the ticker symbol “ARLP”. We were 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. ARH was previously owned by current and former management of the ARLP Partnership. In June 2006, our special general partner, SGP, and its parent, ARH, became wholly-owned, directly and indirectly, by Joseph W. Craft, III, our President and Chief Executive Officer.

We are managed by our managing general partner, MGP. AHGP is a Delaware limited partnership that was formed to own and become the controlling member of MGP. AHGP completed its initial public offering (“IPO”) on May 15, 2006. Upon the closing of the IPO, AHGP owns directly and indirectly 100% of the members’ interest of MGP, a 0.001% managing interest in Alliance Coal, the incentive distribution rights in ARLP and 15,550,628 common units of ARLP.

The accompanying condensed consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of September 30, 2006 and December 31, 2005, results of our operations for the three months and nine months ended September 30, 2006 and 2005 and our cash flows for the nine months ended September 30, 2006 and 2005. All material intercompany transactions and accounts of the ARLP Partnership have been eliminated.

On September 15, 2005, we completed a two-for-one split of ARLP’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. For all periods presented, 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 the unit split.

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

These condensed consolidated financial statements and notes are prepared pursuant to the rules and regulations of the Securities and Exchange Commission for interim reporting and should be read in conjunction with the consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2005.

2. CONTINGENCIES

We are involved in various lawsuits, claims and regulatory proceedings incidental to our business. Currently, we are not engaged in any litigation that we believe is material to our operations, including without limitation, any litigation relating to any of our long-term supply contracts or under the various environmental protection statutes to which we are subject. We provide 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 any litigation matters to the extent not previously provided for or covered under insurance, is not expected to have a material adverse effect on our 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 our financial position or results of operations.

During September 2006, we completed our annual property and casualty insurance renewal with various insurance coverages effective as of October 1, 2006. Available capacity for underwriting property insurance continues to be limited as a result of insurance carrier losses in the mining industry and our recent insurance claims history (e.g., MC Mining Fire Incident and Dotiki Fire Incident). As a result, we have elected to retain a participating interest along with our insurance carriers at an average rate of approximately 14.7% in the overall $75.0 million commercial property program representing 35% of the primary $30.0 million layer and 2.5% of the second layer representing $20.0 million in excess of the $30.0 million primary layer. We do not participate in the third layer of $25.0 million excess of $50.0 million. The 14.7% participation rate for this year’s renewal exceeds the approximate 10% participation level from last year. The aggregate maximum limit in the commercial property program is $75.0 million per occurrence of which, as a result of our participation, we would be responsible for a maximum amount of $11.0 million for each occurrence, excluding a $1.5 million deductible for property damage, a $5.0 million aggregate deductible for extra expense and a 60-day waiting period for business interruption. As a result of our increased participation in the property program and higher deductible levels, property premiums paid to the insurance carriers were reduced by approximately 14.5%. We can make no assurances that we will not experience significant insurance claims in the future, which as a result of our level of 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.

On October 12, 2004, Pontiki Coal, LLC (“Pontiki”) one of our 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 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, which we refer to as the Horizon Agreement. ICG has represented that it acquired the rights and assumed the liabilities of the Horizon Agreement effective September 30, 2004, as part of an asset sale approved by the U.S. Bankruptcy Court supervising the bankruptcy proceedings of Horizon Sales and its affiliates.

The complaint alleged that from January 2004 to August 2004, Pontiki failed to deliver a total of 138,111 tons of coal that met the contract delivery and quality specifications resulting in an alleged loss of profits for ICG of $4.1 million. We are 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. In November 2005, we settled this contract dispute with ICG. Under this settlement, effective August 1, 2005, Pontiki will ship coal in approximately ratable monthly quantities until the remaining contract obligation of 1,681,303 tons is shipped, and this contract will terminate on or by December 31, 2006. Under the terms of the settlement, the existing coal supply agreement was amended to change the coal quality specifications and to exclude from the definition of “force majeure” the events of railroad car shortages and geological and quality issues with respect to coal. As part of this settlement, we also executed a new coal sales agreement with ICG whereby another subsidiary of ours will purchase 892,000 tons of coal from ICG. Approximately 63,000 tons and 424,000 tons were purchased and sold at a profit during 2005 and the nine months ended September 30, 2006, respectively, and the remaining 405,000 tons are expected to be purchased and sold at a profit during the remainder of 2006 and the first half of 2007. These agreements will expire on or by December 31, 2006. However, in the third quarter of 2006, ICG agreed to allow Pontiki to carryover any shortfall of tonnage under this contract into 2007.

At certain of our operations, property tax assessments for several years are under audit by various state tax authorities. We believe that we have recorded adequate liabilities based on reasonable estimates of any property tax assessments that may be ultimately assessed as a result of these audits.

In June 2006, our Intermediate Partnership entered into a guarantee agreement in which it guaranteed the performance of a third party with respect to an agreement to purchase electricity. The term of the guarantee expires at the earlier of January 31, 2007 or the date the agreement to purchase electricity is terminated. Under the terms of the guarantee, if the third party does not fulfill its payment obligation under the agreement to purchase electricity, our Intermediate Partnership is liable for the amounts not paid by the third party. If our Intermediate Partnership were to become liable, the maximum amount of potential future payments is $2.0 million at September 30, 2006. The fair value of the guarantee is not considered material to the consolidated financial statements.

In March 2004, XL Specialty Insurance Company (“XL”) filed litigation against ARH and us in state court of Oklahoma alleging that we and ARH had failed to indemnify XL for Alliance Coal’s failure to pay certain annual premiums associated with four surety bonds issued to the State of Kentucky to secure Alliance Coal’s self-insurance workers’ compensation status. All four of these surety bonds were cancelled by XL in 2001 after it made the business decision to withdraw from the surety market. In the lawsuit, XL requested that the trial court determine, under two indemnity agreements, we and ARH be found jointly and severely liable to XL for bond premiums on the four cancelled surety bonds in the total principal amount of approximately $397,000, plus pre- and post-judgment interest. In answering the lawsuit, we and ARH filed a counterclaim against XL raising a number of affirmative defenses and counterclaiming for breach of contract and bad faith. In July 2006, a bench trial occurred in which XL alleged that Alliance Coal owed approximately $876,000 (including interest) through September 2005. In support of its counterclaim, we and ARH alleged damages of approximately $400,000 relating to certain increased costs associated with Alliance Coal’s surety bond program. In September, 2006, an adverse decision regarding this matter was received from the trial court. Accordingly, we have recorded a liability and expense to reflect the approximate damages determination made by the trial court for the period

through September 30, 2005 and additional estimated expenses through September 30, 2006. We have appealed the state district court’s determination to the Oklahoma Supreme Court. In addition, settlement discussions recently have been initiated between the parties. However, we cannot give assurance that the outcome of the appeal or settlement process will differ materially from our current estimated liability recorded.

3. ACQUISITIONS

In January 2005, we acquired 100% of the limited liability company member interests of Tunnel Ridge, LLC (“Tunnel Ridge”), for approximately $500,000 and the assumption of reclamation liabilities from ARH. Tunnel Ridge controls through a coal lease agreement with our special general partner, 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. Under the terms of the coal lease, beginning on January 1, 2005, Tunnel Ridge has paid and will continue to pay the SGP an advance minimum royalty of $3.0 million per year. The advance royalty payments are fully recoupable against earned royalties.

In April 2006, we acquired 100% of the membership interest in River View Coal, LLC (“River View”) for approximately $1.65 million from ARH. River View controls through a coal lease agreement approximately 89.7 million tons of high sulfur coal reserves and directly owns approximately 9.6 million tons of high sulfur coal reserves in the Kentucky No. 7, No. 9 and No. 11 coal seams. Under the terms of the coal lease agreements, River View paid $1.0 million in minimum royalty payments in 2005 and must pay a minimum of $250,000 in royalties per year thereafter. River View had the right to purchase certain assets, including coal reserves, surface properties, facilities and permits, from the lessor for $4.15 million plus an overriding royalty on all coal mined and sold by River View from certain of its other leased properties. In April 2006, River View purchased such assets and assumed reclamation liabilities of $2.9 million from the lessor.

The Tunnel Ridge and River View transactions described above were related-party transactions and, as such, were reviewed by the Board of Directors of our managing general partner and its conflicts committee. Based upon these reviews, the conflicts committee determined that these transactions reflect market-clearing terms and conditions customary in the coal industry. As a result, the Board of Directors and its conflicts committee approved the Tunnel Ridge and River View acquisitions as fair and reasonable to us and our limited partners. Because the Tunnel Ridge and River View acquisitions were between entities under common control, they have been accounted for at historical cost.

4. 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 September 30, 2006, 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 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 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 estimate of our expenses and losses, with an update through July 31 2005. Partial payments of $4.0 million and $12.2 million were received, during the nine months ended September 30, 2006 and the year ended December 31, 2005, respectively. These amounts are net of the 2005 Deductibles and 2005 Co-Insurance. 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. On March 23, 2006, we filed a third partial proof of loss for the period through July 31, 2005 of $4.0 million. 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, $0.4 million and $10.6 million, during the nine months ended September 30, 2006 and 2005, respectively, and $10.7 million for the year ended December 31, 2005. These 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.

5. NET INCOME PER LIMITED PARTNER UNIT

In March 2004, the Financial Accounting Standards Board (“FASB”) issued Emerging Issues Task Force (“EITF”) No. 03-6, which addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. Essentially, EITF No. 03-6 provides that in any accounting period where our aggregate net income exceeds the aggregate distributions to unitholders for such period, we are required to present earnings per unit as if all of the earnings for the periods were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during a particular period from an economic probability standpoint. EITF No. 03-6 was effective for fiscal periods beginning after March 31, 2004. EITF No. 03-6 does not impact our aggregate distributions to unitholders for any period, but it can have the impact of reducing the earnings per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights held by our managing general partner, even though we make cash distributions on the basis of cash available for distributions to unitholders, not earnings, in any given accounting period. In accounting periods where aggregate net income does not exceed our aggregate distributions for such period, EITF No. 03-6 does not have any impact on our earnings per unit calculation. 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,
	2006			2005			2006			2005
Net income	$	38,640		$	34,481		$	127,439		$	114,352
Adjustments:
General partners’ priority distributions		(5,386	)		(2,264	)		(14,731	)		(5,439	)
General partners’ 2% equity ownership		(665	)		(644	)		(2,254	)		(2,178	)

Limited partners’ interest in net income	$	32,589		$	31,573		$	110,454		$	106,735
Additional earnings allocation to general partners		(7,041	)		(8,104	)		(28,051	)		(30,931	)

Net income available to limited partners under EITF No. 03-6	$	25,548		$	23,469		$	82,403		$	75,804

Weighted average limited partner units – basic		36,426			36,261			36,426			36,261

Basic net income per limited partner unit	$	0.70		$	0.65		$	2.26		$	2.09

Weighted average limited partner units – basic		36,426			36,261			36,426			36,261

Units contingently issuable:
Restricted units for Long-Term Incentive Plan		243			597			217			597
Directors’ compensation units		43			38			42			37
Supplemental Executive Retirement Plan		113			101			111			100

Weighted average limited partner units, assuming dilutive effect of restricted units		36,825			36,997			36,796			36,995

Diluted net income per limited partner unit	$	0.69		$	0.63		$	2.24		$	2.05

Our net income for partners’ capital purposes is allocated to the general partners and limited partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions, if any, to our managing general partner, the holder of the incentive distributions rights pursuant to the ARLP Partnership Agreement, which are declared and paid following the close of each quarter. For purposes of computing basic and diluted net income per limited partner unit, in periods when our aggregate net income exceeds the aggregate distributions to unitholders for such periods, an increased amount of net income is allocated to the general partner for the additional pro forma priority income attributable to the application of EITF No. 03-6.

Our managing general partner is entitled to receive incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions of our partnership agreement, generally, our managing general partner is entitled to receive 15% of the amount we distribute in excess of $0.275 per unit, 25% of the amount we distribute in excess of $0.3125 per unit and 50% of the amount we distribute in excess of $0.375 per unit.

6. COMMON UNIT-BASED COMPENSATION

Effective January 1, 2000, our managing general partner adopted the Long-Term Incentive Plan (“LTIP”) for certain employees and directors of our managing general partner and its affiliates, who perform services for us. Annual grant levels and vesting provisions for designated participants are recommended by our President and Chief Executive Officer, subject to the review and approval of the compensation committee of the board of directors of our managing general partner (“Compensation Committee”). Grants are made either of restricted units, which are “phantom” units that entitle the grantee to receive an ARLP common unit or an equivalent amount of cash upon the vesting of the phantom unit,

or options to purchase ARLP common units. ARLP common units to be delivered upon the vesting of restricted units or to be issued upon exercise of a unit option will be acquired by our managing general partner in the open market at a price equal to the then prevailing price, or directly from an affiliate or any other third party, including units newly issued by ARLP, units already owned by our managing general partner, or any combination of the foregoing. Our partnership agreement provides that our managing general partner be reimbursed for all costs incurred in acquiring these common units or in paying cash in lieu of common units upon vesting of the restricted units. On December 22, 2005, the Compensation Committee executed a unanimous consent resolution that, effective January 1, 2006, (a) all existing grants made under the LTIP prior to January 1, 2006 and subsequent thereto be settled, upon satisfaction of any applicable vesting requirements, in common units to the extent of net share settlement for minimum statutory income tax withholding requirements for each individual participant based upon the fair market value of the common units as of the date of payment and (b) any existing and prospective LTIP grants of restricted units receive quarterly distributions as provided in the distribution equivalent rights provision of the LTIP. Therefore, each LTIP participant has the contingent right to receive an amount equal to the cash distributions made by the ARLP Partnership during the vesting period.

The aggregate number of units reserved for issuance under the LTIP is 1,200,000. Effective January 1, 2004, the Compensation Committee approved an amendment to the LTIP clarifying that any award that is forfeited, expires for any reason, or is paid or settled in cash, including the satisfaction of minimum statutory income tax withholding requirements, rather than through the delivery of units will be available for future grants under the LTIP. Of the initial 1,200,000 units reserved for issuance under the LTIP, cumulative units of 1,092,780 were granted in years 2000, 2001, 2002 and 2003. Of those grants, 43,650 units were forfeited and 421,452 units were settled in cash rather than delivery of units, resulting in the net issuance of 627,678 common units under those grants. During 2004, 2005 and 2006, the Compensation Committee approved grants of 205,570 units, 114,390 units and 85,275 units, respectively, which will vest December 31, 2006, January 1, 2008 and January 1, 2009, respectively, subject to the satisfaction of certain financial tests that management currently believes will be satisfied. Subsequent to the compensation committee approval of the 85,275 2006 grants described above, an additional 2,525 grants were approved to new participants and an existing participant who received a promotion during the year. These additional grants will vest January 1, 2009 bringing the total 2006 grants to 87,800. As of September 30, 2006, 13,440 outstanding LTIP grants have been forfeited. During the three and nine months ended September 30, 2006 and 2005 our managing general partner charged the ARLP Partnership approximately $1,171,000, $5,728,000, $3,100,000 and $9,565,000 respectively, attributable to the LTIP.

Effective January 1, 2006, we adopted the fair value recognition provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123R, Share-Based Payment, using the “modified prospective” transition method. 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 that date, 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 used the modified prospective method of adoption provided under SFAS No. 123R and, therefore, did not restate prior period results.

We historically accounted for the compensation expense of the non-vested restricted common units granted under the LTIP using the intrinsic value method prescribed in Accounting Principles Board Opinion (“APB”) No. 25, Accounting for Stock Issued to Employees and the related FASB Interpretation No. 28, Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans. Compensation cost for the restricted common units was recorded on a pro-rata basis, as appropriate given

the “cliff vesting” nature of the grants, based upon the current market value of the ARLP Common Units at the end of each period. Because we had previously expensed share-based payments using the current market value of the ARLP Common Units at the end of each period, the adoption of SFAS No. 123R did not have a material impact on our consolidated results of operations.

The intrinsic value of the 2005 and 2004 grants of $37.20 per LTIP grant at December 31, 2005 essentially equals the fair value at January 1, 2006 and, therefore, no incremental compensation cost was recognized upon adoption of SFAS No. 123R. As required by SFAS No. 123R, the fair value was reduced for expected forfeitures, to the extent compensation cost had been previously recognized and we recorded a benefit of $112,000 upon adoption of SFAS No. 123R on January 1, 2006 as a cumulative effect of accounting change. We expect to settle the non-vested LTIP grants by delivery of ARLP common units, except for the portion of the grants that will satisfy the minimum statutory income tax withholding requirements. Consequently, the previously recognized liability reflected in the due to affiliates current and long-term accounts in our consolidated balance sheet at December 31, 2005 was reclassified to partners’ capital upon adoption of SFAS No. 123R on January 1, 2006. The fair value of the 2006 grants is based upon the intrinsic value at the date of grant which was $37.91 per LTIP grant.

A summary of non-vested LTIP grants as of and for the nine months ended September 30, 2006 is as follows:


Non-vested grants at January 1, 2006	316,270
Granted	87,800
Vested	—
Forfeited	(9,750	)

Non-vested grants at September 30, 2006	394,320

As of September 30, 2006, there was $4,465,000 in total unrecognized compensation cost related to the non-vested LTIP grants. That cost is expected to be recognized over a weighted-average period of 0.9 years. As of September 30, 2006, the intrinsic value of the non-vested LTIP grants was $13,019,000.

The total obligation associated with the LTIP as of September 30, 2006 was $9,497,000 and is included in partners’ capital-limited partners, contained in our condensed consolidated balance sheets. The total obligation associated with the LTIP as of December 31, 2005 was $6,517,000 and is included in the current and long-term liabilities due to affiliates contained in our condensed consolidated balance sheets.

Consistent with the 2005 disclosure requirements of 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 costs 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, 2005			Nine Months Ended September 30, 2005
Net income, as reported	$	34,481		$	114,352

Add: compensation expenses related to Long-Term Incentive Plan units included in reported net income		5,728			9,565

Deduct: compensation expense related to Long-Term Incentive Plan units determined under fair value method for all awards		(5,728	)		(9,565	)

Net income, pro forma	$	34,481		$	114,352

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

Limited partners’ interest in net income, pro forma	$	31,573		$	106,735

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

Basic, pro forma	$	0.65		$	2.09

Diluted, as reported	$	0.63		$	2.05

Diluted, pro forma	$	0.63		$	2.05

7. COMPONENTS OF PENSION PLAN NET PERIODIC BENEFIT COSTS

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Service cost	$	829		$	813		$	2,487		$	2,438
Interest cost		487			418			1,461			1,253
Expected return on plan assets		(568	)		(483	)		(1,702	)		(1,448	)
Prior service cost		10			13			32			38
Net loss		79			50			235			150

	$	837		$	811		$	2,513		$	2,431

As of September 30, 2006 and 2005, we have made contributions of $4,600,000 and $3,000,000, respectively, to the Pension Plan.

8. MINE DEVELOPMENT

We have mine development activities in progress at our Mountain View underground mine. 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.

9. NEW ACCOUNTING STANDARDS

In November 2004, the FASB issued SFAS No. 151, Inventory Costs (“SFAS No. 151”). 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. This statement 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. Our adoption of SFAS No. 151 on January 1, 2006 did not affect our consolidated financial statements.

We adopted SFAS No. 123R effective on January 1, 2006. We used the modified prospective method of adoption provided under SFAS No. 123R and, therefore, did not restate prior period results (Note 6).

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, our adoption of EITF No. 04-6, effective January 1, 2006 did not have a material impact on our consolidated financial statements.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (“FIN 48”). This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. The interpretation prescribes a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. We are currently in the process of assessing the provisions of FIN 48, but do not expect the adoption of FIN 48 to have a material impact on our consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). This standard defines fair value, establishes a framework for measuring fair value in accounting principles generally accepted in the United States of America, and expands disclosure about fair value measurements. SFAS No. 157 applies under other accounting standards that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurement. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the requirements of SFAS No. 157 and have not yet determined the impact on our consolidated financial statements.

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS No. 158”). SFAS No. 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset

or liability on its statement of financial position. SFAS No. 158 also requires an employer to recognize changes in that funded status in the year in which the changes occur through comprehensive income. In addition, SFAS No. 158 requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position. SFAS No. 158 requirements to recognize the funded status of a benefit plan and new disclosure requirements are effective as of December 31, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. We do not expect the adoption of SFAS No. 158 to have a material impact on our consolidated financial statements at December 31, 2006.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements (“SAB 108”), which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. SAB 108 is effective as of December 31, 2006. We are currently in the process of assessing SAB 108 but do not expect the adoption of SAB 108 to have a material impact on our consolidated financial statements.

10. COMPREHENSIVE INCOME

The following table summarizes the effect of our marketable securities available for sale in other comprehensive income for the three and nine months ended September 30, 2006 and 2005, respectively, (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Net income	$	38,640	$	34,481	$	127,439	$	114,352
Unrealized gain (loss)		2		18		68		(17	)

Comprehensive income	$	38,642	$	34,499	$	127,507	$	114,335

Comprehensive income differs from net income by the amount of unrealized gain or loss resulting from valuation changes of our marketable securities available for sale.

11. SEGMENT INFORMATION

We operate in the eastern United States as a producer and marketer of coal to major United States utilities and industrial users, also located in the eastern United States. We have the following three reportable segments: the Illinois Basin, Central Appalachia and Northern Appalachia. The segments also represent the three major coal deposits in the eastern United States. Coal quality, coal seam height, transportation methods and regulatory issues are similar within each of these three segments. The Illinois Basin segment is comprised of the Dotiki, Gibson, Hopkins, Elk Creek, Pattiki, River View and Warrior mines. Central Appalachia segment is comprised of the Pontiki and MC Mining mines. Northern Appalachia segment is comprised of the Mettiki, Mountain View, Tunnel Ridge and Penn Ridge mines. The Mountain View mine is currently being developed to replace production from the Mettiki longwall mine, which is expected to deplete its coal reserves in the fourth quarter of 2006. We are in the process of permitting the River View and Tunnel Ridge mines, and the Gibson South and Penn Ridge properties for future mine development.

Operating segment results for the three months and nine months ended September 30, 2006 and 2005 are presented below. Other and Corporate, includes marketing and administrative expenses, the Mt. Vernon Transfer Terminal and coal brokerage activity.


	Illinois Basin		Central Appalachia		Northern Appalachia		Other and Corporate (1)		Consolidated
	(in thousands)
Operating segment results for the three months ended September 30, 2006 were as follows:

Total revenues	$	159,964	$	43,562	$	33,518	$	7,696	$	244,740
Selected production expenses (2)		91,143		30,751		17,049		6,294		145,237
Segment Adjusted EBITDA (3)		47,911		7,114		9,422		1,314		65,761
Capital expenditures (4)		27,357		7,590		13,961		1,038		49,946

Operating segment results for the three months ended September 30, 2005 were as follows:

Total revenues	$	135,576	$	44,564	$	25,965	$	938	$	207,043
Selected production expenses (2)		70,312		25,914		15,153		621		112,000
Segment Adjusted EBITDA (3)		46,462		12,494		5,526		167		64,649
Capital expenditures (4)		18,484		5,938		8,568		307		33,297

	Illinois Basin		Central Appalachia		Northern Appalachia		Other and Corporate (1)		Consolidated
	(in thousands)
Operating segment results for the nine months ended September 30, 2006 were as follows:

Total revenues	$	459,549	$	139,686	$	86,905	$	18,224	$	704,364
Selected production expenses (2)		251,050		91,901		44,898		13,153		401,002
Segment Adjusted EBITDA (3)		146,606		30,761		24,172		4,206		205,745
Total assets		342,919		98,220		109,363		53,873		604,375
Capital expenditures (4)		86,818		17,808		27,612		9,725		141,963

Operating segment results for the nine months ended September 30, 2005 were as follows:

Total revenues	$	410,183	$	110,704	$	87,791	$	2,708	$	611,386
Selected production expenses (2)		213,209		66,824		44,601		1,253		325,887
Segment Adjusted EBITDA (3)		138,954		29,214		27,046		968		196,182
Total assets		255,597		82,399		67,442		93,279		498,717
Capital expenditures (4)		48,096		15,426		16,256		825		80,603

(1)	Total Revenues included in the Other and Corporate column are principally comprised of Mt. Vernon Transfer Terminal transloading revenues, administrative service revenue from affiliates and brokerage coal sales.

(2)	Selected production expenses is comprised of operating expenses and outside purchases (as reflected in the condensed consolidated statements of income), excluding production taxes and royalties that are incurred as a percentage of coal sales or volumes.

(3)

Segment Adjusted EBITDA is defined as net income before income taxes, cumulative effect of accounting change and minority interest, interest expense and interest income, depreciation, depletion and amortization, and general and administrative expense. Segment Adjusted EBITDA is reconciled to net income below.

(4)	Capital expenditures includes items received but not yet paid, which is disclosed as non-cash activity, purchase of property, plant and equipment in the supplemental cash flow information in the condensed consolidated

statements of cash flows. Capital expenditures do not include business acquisitions separately reported in the condensed consolidated statements of cash flows.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
	(in thousands)
Reconciliation of Segment Adjusted EBITDA to net income:

Segment Adjusted EBITDA	$	65,761		$	64,649		$	205,745		$	196,182
General & administrative		(7,391	)		(12,812	)		(21,640	)		(29,067	)
Depreciation, depletion and amortization		(17,273	)		(13,798	)		(48,283	)		(40,822	)
Interest expense, net		(2,158	)		(2,841	)		(6,933	)		(9,685	)
Income taxes		(352	)		(717	)		(1,658	)		(2,256	)
Cumulative effect of accounting change		—			—			112			—
Minority interest		53			—			96			—

Net income	$	38,640		$	34,481		$	127,439		$	114,352

Reconciliation of Selected Production Expenses to Combined Operating Expenses and Outside Purchases:
Selected production expenses	$	145,237		$	112,000		$	401,002		$	325,887
Production taxes and royalties		22,992			21,384			68,345			62,524

Combined operating expenses and outside purchases	$	168,229		$	133,384		$	469,347		$	388,411

12. MINORITY INTEREST

In March 2006, White County Coal, LLC (“White County Coal”), a subsidiary of the ARLP Partnership, and Alexander J. House (“House”) entered into a limited liability company agreement to form Mid-America Carbonates, LLC (“MAC”). MAC was formed to engage in the development and operation of a rock dust mill. The main purpose of the rock dust mill will be to manufacture and sell rock dust. In coal mining, rock dust normally consists of finely milled limestone, which is applied to haulage ways and mine entries or corridors in such quantities that the combination of coal dust, rock dust and other dust forms an incombustible content. MAC and Alliance Coal have entered into a six year rock dust supply agreement in which MAC will supply the greater of 50,000 tons or 70% of the aggregate amount of rock dust used by our subsidiaries located in the Illinois Basin. For the first three years of the contract, our subsidiaries will purchase the rock dust at 125% of MAC’s actual production cost. Any rock dust tonnage purchased above 70% used by the Alliance Coal’s subsidiaries in the Illinois Basin will be priced at the prevailing market rate. After three years, the price paid by our mines to MAC will reopen to market.

White County Coal’s initial investment was $1.0 million in exchange for a 50% equity interest in MAC. We consolidate MAC’s financial results in accordance with FASB Interpretation No. 46R (“FIN 46R”). Based on the guidance in FIN 46R, we concluded that MAC is a variable interest entity and that we are the primary beneficiary. House’s equity ownership in the net assets of MAC was $904,000 as of September 30, 2006, which is recorded as minority interest on our condensed consolidated balance sheet.

13. RELATED PARTY TRANSACTION

In connection with the closing of the IPO of AHGP, we entered into an Administrative Services Agreement between our managing general partner, our operating subsidiary, AHGP and Alliance Resource Holdings II, Inc. (“ARH II”), which is the parent of ARH. Under the Administrative Services Agreement, certain of our own personnel, including executive officers, are providing administrative

services to our managing general partner, AHGP, Alliance GP, LLC (“AGP”) (general partner of AHGP), ARH II and their respective affiliates. We will be reimbursed for services rendered by our employees on behalf of these affiliates as provided under the Administrative Services Agreement. We billed and recognized administrative service revenue under these agreements of $218,000 and $696,000, respectively, for the three and nine months ended September 30, 2006. Concurrently, AHGP, AGP and our managing general partner joined as parties to our Omnibus Agreement, which addresses areas of non-competition between AHGP and us.

Because the Administrative Services Agreement transaction described above was a related-party transaction, it was reviewed by the Board of Directors of our managing general partner and its conflicts committee. Based upon this review, the conflicts committee 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 Administrative Services Agreement transaction as fair and reasonable to us and our limited partners.

14. SUBSEQUENT EVENTS

On October 26, 2006, we declared a quarterly distribution for the quarter ended September 30, 2006, of $0.50 per unit, totaling approximately $24.0 million (which includes the our managing general partners’ incentive distributions), on all our common units outstanding, payable on November 14, 2006 to all unitholders of record as of November 6, 2006.

On November 8, 2006, AHGP contributed 6,459 units of ARLP to our managing general partner. Our managing general partner contributed the ARLP units to ARLP in exchange for a limited partner interest in our Intermediate Partnership. The unit contribution by our managing general partner was necessary to maintain its 1.0% GP interest in the Intermediate Partnership.

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

SIGNIFICANT RELATIONS REFERENCED IN THIS MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

•

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

•

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

•

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

•

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

•

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

•

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

SUMMARY

We are a diversified producer and marketer of coal to major United States utilities and industrial users. We began mining operations in 1971 and, since then, have grown through acquisitions and internal development to become what we believe to be the fifth largest coal producer in the eastern United States. We currently operate eight underground mining complexes in Illinois, Indiana and Kentucky, and we are currently transitioning our existing Mettiki longwall operation in Maryland, which will deplete its reserves in the fourth quarter of 2006, to our Mountain View mine in West Virginia. We also lease land and operate a coal loading terminal on the Ohio River at Mt. Vernon, Indiana, which we refer to as the Mt. Vernon Transfer Terminal.

We reported quarterly net income for the three months ended September 30, 2006 (the 2006 Quarter) of $38.6 million compared to $34.5 million for the three months ended September 30, 2005 (the 2005 Quarter). Our performance for the quarter benefited from increased coal production as well as higher average coal sales prices which were partially offset by lower synfuel-related revenues and higher operating expenses. We have contractual commitments for substantially all of our remaining estimated 2006 production.

We have entered into agreements with the owners of three coal synfuel production facilities: (1) Synfuel Solutions Operating, LLC (SSO), related to its coal synfuel facility located at our Warrior Coal, LLC (Warrior) mining complex in Hopkins County, Kentucky; (2) PC Indiana Synthetic Fuel #2, L.L.C. (PCIN), related to its coal synfuel facility located at our Gibson County Coal, LLC (Gibson) mining complex in Gibson County, Indiana; and (3) Mt. Storm Coal Supply, LLC (Mt. Storm Coal Supply), related to its coal synfuel facility located at Virginia Electric and Power Company’s Mt. Storm power

station, which is adjacent to our Mettiki Coal, LLC (Mettiki) mining complex in Garrett County, Maryland. SSO, PCIN, and Mt. Storm Coal Supply are collectively referred to below as Coal Synfuel Owners.

We receive revenues from coal sales, rental, marketing and other services provided to the Coal Synfuel Owners pursuant to various long-term agreements associated with their respective coal synfuel facilities. Each of these agreements, which expire on December 31, 2007, are dependent on the ability of the Coal Synfuel Owners to use certain qualifying federal income tax credits available to their respective coal synfuel facilities and are subject to early cancellation if the synfuel tax credits become unavailable due to a rise in the price of domestic crude oil or otherwise. Pursuant to our agreements with the Coal Synfuel Owners, we are not obligated to make retroactive adjustments or reimbursements if synfuel credits are disallowed.

Due to the increase in wellhead price of domestic crude oil, the operational status of our synfuel operations has been sporadic. As of the date of this report, each of our Coal Synfuel Owners are operating and are currently producing coal synfuel. Each of the Coal Synfuel Owners has advised us that future operation of their respective synfuel facilities is dependent on the future price of crude oil. During the suspension of operations at the coal synfuel production facilities located at Warrior, Gibson and Mettiki, respectively, we sold coal directly to the Coal Synfuel Owners’ customers under “back-up” coal supply agreements, which automatically provide for the sale of our coal in the event these customers do not purchase coal synfuel.

In connection with the initial public offering (IPO) of AHGP, Alliance Management Holdings, LLC (AMH) and AMH II, LLC (AMH II), the previous owners of our managing general partner and our special general partner, entered into a contribution agreement pursuant to which, upon closing of the IPO, AHGP owns, directly and indirectly, 100% of the members’ interest in MGP, a 0.001% managing interest in Alliance Coal, our operating subsidiary, the incentive distribution rights and 15,550,628 of our common units. As consideration for this contribution and in accordance with the terms of the contribution agreement, AHGP distributed to AMH, AMH II and SPG substantially all the proceeds from its IPO as well as 79.1% of its common units. Our special general partner and its parent, Alliance Resource Holdings, Inc. (ARH), were formally owned by our management. In June 2006, ARH and its parent company became wholly-owned, directly and indirectly, by Joseph W. Craft, III, our President and Chief Executive Officer.

RESULTS OF OPERATIONS

Three Months Ended September 30, 2006 Compared to Three Months Ended September 30, 2005


	September 30,				September 30,
	2006		2005		2006		2005
	(in thousands)				(per ton sold)
Tons sold		6,164		5,589		N/A		N/A
Tons produced		6,114		5,351		N/A		N/A
Coal sales	$	228,802	$	189,639	$	37.12	$	33.93
Operating expenses and outside purchases	$	168,229	$	133,384	$	27.29	$	23.87

Coal sales. Coal sales for the 2006 Quarter increased 20.7% to $228.8 million from $189.6 million for the 2005 Quarter. The increase of $39.2 million is a result of higher coal sales prices (contributing to $19.7 million of the increase) and increased sales volumes (contributing to $19.5 million of the increase). Tons sold were 6.2 million and 5.6 million for the 2006 and 2005 Quarters, respectively.

Tons produced increased 14.3% to 6.1 million tons for the 2006 Quarter from 5.4 million tons for the 2005 Quarter.

Operating expenses. Operating expenses increased 24.9% to $162.2 million for the 2006 Quarter from $129.9 million for the 2005 Quarter. The increase of $32.3 million resulted from higher operating expenses associated with additional coal sales of 575,000 tons, including the following specific factors:

•

Labor and benefit costs increased $10.6 million reflecting increased headcount, pay rate increases and escalating health care costs;

•

Material and supplies, and maintenance costs increased $10.9 million and $2.1 million, respectively, reflecting increased costs for certain products and services used in the mining process;

•

Production taxes and royalties (which are incurred as a percentage of coal sales or volumes) increased $1.6 million;

•

Workers compensation increased $2.0 million as a result of adverse claims development.

•

Property insurance costs increased $1.4 million;

•

Costs of $4.6 million in the 2006 Quarter were associated with the purchase of tons under the settlement agreement we entered into with ICG, LLC (ICG) in November 2005. Consistent with the guidance in the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force (EITF) No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, Pontiki’s sale of coal to ICG and Alliance Coal’s purchase of coal from ICG are combined. Therefore, the excess of Alliance Coal’s purchase price from ICG over Pontiki’s sales price to ICG is reported as an operating expense; and

•

The 2006 Quarter operating expenses were decreased by $2.0 million more than the decrease in the 2005 Quarter, reflecting greater costs incurred and capitalized in the mine development process offset by revenues received for coal produced incidental with the mine development process. See Note 8. Mine Development to the Unaudited Condensed Consolidated Financial Statements included in “Item 1, Financial Statements (Unaudited)” of this quarterly report on Form 10-Q.

General and administrative. General and administrative expenses decreased to $7.4 million for the 2006 Quarter compared to $12.8 million for the 2005 Quarter. The decrease of $5.4 million was primarily attributable to a reduction in unit-based incentive compensation expense associated with the Long-Term Incentive Plan (LTIP) and Supplemental Executive Retirement Plan in addition to the Short-Term Incentive Plan (STIP). Prior to our adoption of Statement of Financial Accounting Standards (SFAS) No. 123R, Shared-Based Payment, effective January 1, 2006 using the “modified prospective” transition method, our LTIP expense was impacted by period-to-period changes in our common unit price.

Other sales and operating revenues. Other sales and operating revenues is principally comprised of service fees from coal synfuel production facilities, Mt. Vernon Transfer Terminal transloading revenues and administrative service revenue from affiliates. Other sales and operating revenues decreased 40.1% to $5.0 million for the 2006 Quarter from $8.3 million for the 2005 Quarter. The decrease of $3.3 million is primarily attributable to a reduction in rental and service fees associated with decreased volumes at third-party coal synfuel facilities. Please read “Item 2. Management’s Discussion

and Analysis of Financial Condition and Results of Operations – Summary” above for a discussion regarding the status of third-party coal synfuel facilities.

Outside purchases. Outside purchases increased to $6.0 million for the 2006 Quarter from $3.5 million in the 2005 Quarter. The increase of $2.5 million was primarily attributable to an increase in outside purchases at our Central and Northern Appalachia operations to supply new market opportunities, partially offset by lower outside purchases in our Illinois Basin operations.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $17.3 million for the 2006 Quarter from $13.8 million for the 2005 Quarter. The increase of $3.5 million is primarily attributable to additional depreciation expense associated with an increase of capital expenditures, particularly at our Elk Creek and Pontiki Van Lear operations, and infrastructure investments in recent years which have increased our production capacity.

Interest expense. Interest expense, net of capitalized interest, decreased to $2.9 million for the 2006 Quarter from $3.7 million for the 2005 Quarter. The decrease of $0.8 million is principally attributable to the capitalization of interest expense related to capital projects and/or mine development costs at Elk Creek, Pontiki, Gibson and Mountain View mines in addition to reduced interest expense associated with the August 2006 and 2005 scheduled principal payments of $18.0 million, respectively on our senior notes. We had no borrowings under the credit facility during the 2006 Quarter.

Interest income. Interest income decreased to $0.7 million for the 2006 Quarter from $0.9 million for the 2005 Quarter. The decrease of $0.2 million resulted from decreased interest income earned on marketable securities, which have been substantially liquidated during the 2006 Quarter to fund increased capital expenditures.

Transportation revenues and expenses. Transportation revenues and expenses increased to $11.0 million for the 2006 Quarter compared to $9.1 million for the 2005 Quarter. The increase of $1.9 million was primarily attributable to higher coal sales volumes for which we arrange transportation. The cost of transportation services are passed through to our customers. Consequently, we do not realize any margin on transportation revenues.

Income before income taxes, cumulative effect of accounting change and minority interest. Income before income taxes, cumulative effect of accounting change and minority interest for the 2006 and 2005 Quarters was $38.9 million and $35.2 million, respectively, and reflects the impact of the changes in revenues and expenses described above.

Income tax expense. Income tax expense decreased to $0.4 million for the 2006 Quarter from $0.7 million for the 2005 Quarter resulting from decreased volumes at a third-party coal synfuel facility.

Minority interest. In March 2006 our subsidiary, White County Coal, LLC (White County Coal) and Alexander J. House (House) entered into a limited liability company agreement to form Mid-America Carbonates, LLC (MAC). MAC was formed to engage in the development and operation of a rock dust mill. The main purpose of the rock dust mill will be to manufacture and sell rock dust. In coal mining, rock dust normally consists of finely milled limestone, which is applied to haulage ways and mine entries or corridors in such quantities that the combination of coal dust, rock dust and other dust forms an incombustible content. We consolidate MAC’s financial results in accordance with FASB Interpretation No. 46R (FIN 46R). Based on the guidance in FIN 46R, we concluded that MAC is a variable interest entity and that we are the primary beneficiary. House’s portion of MAC’s net loss was $53,000 for the 2006 Quarter and is recorded as minority interest on our condensed consolidated income statement.

Our 2006 Quarter Segment Adjusted EBITDA increased $1.1 million, or 1.7%, to $65.8 million from 2005 Quarter Segment Adjusted EBITDA of $64.7 million. Segment Adjusted EBITDA, tons sold, coal sales, operating revenues and Adjusted Segment EBITDA Expense by segment are as follows (in thousands):


	Three Months Ended September 30,
	2006		2005		Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	47,911	$	46,462	$	1,449		3.1	%
Central Appalachia		7,114		12,494		(5,380	)	(43.1	)%
Northern Appalachia		9,422		5,526		3,896		70.5	%
Other and Corporate		1,314		167		1,147		(3	)

Total Segment Adjusted EBITDA (1)	$	65,761	$	64,649	$	1,112		1.7	%

Tons sold
Illinois Basin		4,409		3,882		527		13.6	%
Central Appalachia		793		936		(143	)	(15.3	)%
Northern Appalachia		943		771		172		22.3	%
Other and Corporate		19		—		19		(3	)

Total tons sold		6,164		5,589		575		10.3	%

Coal sales
Illinois Basin	$	150,990	$	123,329	$	27,661		22.4	%
Central Appalachia		42,384		43,757		(1,373	)	(3.1	)%
Northern Appalachia		28,999		22,550		6,449		28.6	%
Other and Corporate		6,429		3		6,426		(3	)

Total coal sales	$	228,802	$	189,639	$	39,163		20.7	%

Other sales and operating revenues
Illinois Basin	$	3,193	$	6,858	$	(3,665	)	(53.4	)%
Central Appalachia		—		—		—		—
Northern Appalachia		513		512		1		0.2	%
Other and Corporate		1,266		934		332		35.5	%

Total other sales and operating revenues	$	4,972	$	8,304	$	(3,332	)	(40.1	)%

Segment Adjusted EBITDA Expense
Illinois Basin	$	106,272	$	83,724	$	22,548		26.9	%
Central Appalachia		35,268		31,263		4,005		12.8	%
Northern Appalachia		20,090		17,536		2,554		14.6	%
Other and Corporate		6,383		771		5,612		(3	)

Total Segment Adjusted EBITDA Expense (2)	$	168,013	$	133,294	$	34,719		26.0	%

(1)

(2)	Segment Adjusted EBITDA Expense includes operating expenses, outside purchases and other income. Pass through transportation expenses are excluded.

(3)	Percentage increase was significantly greater than 100%.

Illinois Basin – Segment Adjusted EBITDA for the 2006 Quarter, as defined in reference (1) to the table above, increased 3.1%, to $47.9 million from the 2005 Quarter Segment Adjusted EBITDA of $46.5 million. The increase of $1.4 million was primarily attributable to increased coal sales which rose by $27.7 million, or 22.4%, to $151.0 million in the 2006 Quarter, as compared to $123.3 million in the 2005 Quarter. Increased coal sales in the 2006 Quarter reflects a higher average coal sales price per ton, which increased $2.47 per ton to $34.24 per ton. Other sales and operating revenues decreased $3.7 million, primarily due to a reduction in rental and service fees associated with decreased volumes at third-party coal synfuel facilities. Total Segment Adjusted EBITDA Expense for the 2006 Quarter increased 26.9% to $106.3 million from $83.7 million in the 2005 Quarter. On a per ton sold basis, 2006 Quarter Segment Adjusted EBITDA Expense rose to $24.10 per ton, an increase of 11.7% over the 2005 Quarter Segment Adjusted EBITDA Expense per ton of $21.57 per ton. The increase in the 2006 Quarter Segment Adjusted EBITDA Expense compared to the 2005 Quarter primarily reflects the impact of cost increases described above under consolidated operating expenses. Additionally, Illinois Basin costs have been negatively impacted by high cost production at the Elk Creek mine which emerged from development in the second quarter of 2006, but has not yet reached full production capacity.

Central Appalachia – Segment Adjusted EBITDA for the 2006 Quarter, as defined in reference (1) to the table above, decreased $5.4 million, or 43.1%, to $7.1 million as compared to the 2005 Quarter Segment Adjusted EBITDA of $12.5 million. The decrease was primarily attributable to cost increases described above under consolidated operating expenses. Additionally, Central Appalachia costs have been negatively impacted by high cost production from the Pontiki Van Lear mine which emerged from development during the fourth quarter of 2005, but has not yet reached full production capacity. The decrease in Segment Adjusted EBITDA was also attributable to decreased coal sales of $1.4 million, reflecting a decrease in tons sold of 143,000 tons (contributing to $6.7 million of the decrease), partially offset by an increase in coal sales prices (resulting in a $5.3 million increase). Segment Adjusted EBITDA Expense for the 2006 Quarter increased 12.8% to $35.3 million from $31.3 million in the 2005 Quarter. The increase in the 2006 Quarter Segment Adjusted EBITDA Expense compared to the 2005 Quarter primarily reflects the impact of cost increases described above under consolidated operating expenses and the high cost of ramping to full production in Pontiki’s Van Lear seam and transitioning to the Albridge Branch area of the Pond Creek seam.

Northern Appalachia – Segment Adjusted EBITDA for the 2006 Quarter, as defined in reference (1) to the table above, increased $3.9 million, or 70.5%, to $9.4 million as compared to the 2005 Quarter Segment Adjusted EBITDA of $5.5 million. The increase was primarily attributable to a $6.4 million increase in coal sales, which reflects an increase average sales price per ton of $1.53 to $30.78 per ton in the 2006 Quarter (which contributed $1.4 million of the increase in coal sales) and increased tons sold of 172,000 tons (which contributed $5.0 million of the increase). On a per ton sold basis, the 2006 Quarter Adjusted EBITDA expense decreased $1.43 per ton due to accelerated coal production and sales volumes related to the completion of production operations at the Mettiki longwall mine.

Other and Corporate – The increase in coal sales and Segment Adjusted EBITDA Expense primarily reflects the coal sales and operating expenses attributable to the brokerage coal purchases and coal sales associated with the ICG agreement described above.

A reconciliation of Segment Adjusted EBITDA to net income is as follows (in thousands):


	Three Months Ended September 30,
	2006			2005
Segment Adjusted EBITDA	$	65,761		$	64,649

General & administrative		(7,391	)		(12,812	)
Depreciation, depletion and amortization		(17,273	)		(13,798	)
Interest expense, net		(2,158	)		(2,841	)
Income taxes		(352	)		(717	)
Minority interest		53			—

Net income	$	38,640		$	34,481

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

We reported record net income for the nine months ended September 30, 2006 (the 2006 Period) of $127.4 million, an increase of 11.4% over the nine months ended September 30, 2005 (the 2005 Period). Increased results for the 2006 Period were primarily attributable to increased coal production and sales volumes, as well as higher average coal sales prices, which benefits were partially offset by increased operating expenses and lower synfuel-related revenues.


	September 30,				September 30,
	2006		2005		2006		2005
	(in thousands)				(per ton sold)
Tons sold		17,836		16,977		N/A		N/A
Tons produced		18,164		16,722		N/A		N/A
Coal sales	$	652,527	$	560,612	$	36.58	$	33.02
Operating expenses and outside purchases	$	469,347	$	388,411	$	26.31	$	22.88

Coal sales. Coal sales increased 16.4% to $652.5 million for the 2006 Period from $560.6 million for the 2005 Period. The increase of $91.9 million reflects increased sales volumes (contributing $28.4 million of the increase) and higher coal sales prices (contributing $63.5 million of the increase). Tons sold increased 5.1% to 17.8 million tons for the 2006 Period from 17.0 million tons for the 2005 Period. Tons produced increased 8.6% to 18.2 million tons for the 2006 Period from 16.7 million tons for the 2005 Period.

Operating expenses. Operating expenses increased 20.6% to $455.1 million for the 2006 Period from $377.4 million for the 2005 Period. The increase of $77.7 million resulted from an increase in operating expenses associated with additional coal sales of 859,000 tons, including the following specific factors:

•

Labor and benefit costs increased $27.0 million reflecting increased headcount, pay rate increases and escalating health care costs;

•

Material and supplies, and maintenance costs increased $29.3 million and $4.6 million, respectively, reflecting increased production and increased costs for certain products and services used in the mining process;

•

Third-party mining costs increased $4.4 million reflecting increased production at two small third-party mining operations at Mettiki;

•

Production taxes and royalties (which are incurred as a percentage of coal sales or volumes) increased $5.8 million;

•

Property insurance costs increased $3.9 million;

•

Workers compensation increased $3.6 million as a result of adverse claims development;

•

Coal supply agreement buy-out expense decreased $1.4 million;

•

Costs of $10.8 million in the 2006 Period were associated with the purchase of tons under the settlement agreement we entered into with ICG in November 2005. Consistent with the guidance in EITF No. 04-13, Pontiki’s sale of coal to ICG and Alliance Coal’s purchase of coal from ICG are combined. Therefore, the excess of Alliance Coal’s purchase price from ICG over Pontiki’s sales price to ICG is reported as an operating expense; and

•

The 2006 Period operating expenses were decreased by $9.2 million more than the decrease in the 2005 Period, reflecting greater costs incurred and capitalized in the mine development process offset by revenues received for coal produced incidental with the mine development process. See Note 8. Mine Development to the Unaudited Condensed Consolidated Financial Statements included in “Item 1, Financial Statements (Unaudited)” of this quarterly report on Form 10-Q.

General and administrative. General and administrative expenses decreased to $21.6 million for the 2006 Period from $29.1 million for the 2005 Period. The decrease of $7.5 million was primarily related to lower unit-based incentive compensation expense associated with the LTIP and STIP. Prior to our adoption of SFAS No. 123R effective January 1, 2006 using the “modified prospective” transition method, our LTIP expense was impacted by period-to-period changes in our common unit price.

Other sales and operating revenues. Other sales and operating revenues decreased 7.5% to $21.9 million for the 2006 Period from $23.7 million for the 2005 Period. The decrease of $1.8 million was primarily attributable to a $2.6 million reduction in rental and service fees associated with decreased volumes at third-party coal synfuel facilities, partially offset by an increase in administrative service revenue of $0.7 million in the 2006 Period. Please read Item 2. Summary above for a discussion regarding the status of third-party coal synfuel facilities.

Outside purchases. The increase in outside purchases to $14.3 million for the 2006 Period from $11.0 million in the 2005 Period was primarily attributable to an increase in outside purchases at our Central and Northern Appalachia operations to supply new market opportunities partially offset by lower outside purchases in Illinois Basin.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $48.3 million for the 2006 Period from $40.8 million for the 2005 Period. The increase of $7.5 million is primarily attributable to additional depreciation expense associated with an increase of capital expenditures, particularly at our Elk Creek and Pontiki Van Lear projects and infrastructure investments in recent years which have increased our production capacity.

Interest expense. Interest expense decreased to $9.5 million for the 2006 Period from $11.6 million for the 2005 Period. The decrease of $2.1 million was principally attributable to the capitalization

of interest expense related to capital projects and/or mine development costs at our Elk Creek, Mountain View, Pontiki and Gibson mines in addition to reduced interest expense associated with the August 2006 and 2005 scheduled principal payments of $18.0 million, respectively on our senior notes. We had no borrowings under the credit facility during the 2006 or 2005 Periods.

Interest Income. Interest income increased to $2.5 million for the 2006 Period from $1.9 million for the 2005 Period. The increase of $0.6 million resulted from increased interest income earned on marketable securities.

Transportation revenues and expenses. Transportation revenues and expenses increased to $30.0 million in the 2006 Period compared to $27.1 million in the 2005 Period. The increase of $2.9 million was primarily attributable to higher sales volumes for which we arrange transportation. The cost of transportation services are passed through to our customers. Consequently, we do not realize any margin on transportation revenues.

Income before income taxes, cumulative effect of accounting change and minority interest. Income before income taxes, cumulative effect of accounting change and minority interest increased to $128.9 million for the 2006 Period from $116.6 million for the 2005 Period. The increase of $12.3 million was primarily attributable to increased sales volumes, higher coal prices and lower general and administrative expense partially offset by higher operating expenses and lower synfuel-related revenues.

Income tax expense. Income tax expense decreased to $1.7 million for the 2006 Period from $2.3 million for the 2005 Period resulting from decreased volumes at a third-party coal synfuel facility.

Cumulative effect of accounting change. The cumulative effect of accounting change $0.1 million was attributable to the adoption of SFAS No. 123R on January 1, 2006.

Minority interest. In March 2006 our subsidiary, White County Coal and House entered into a limited liability company agreement to form MAC. MAC was formed to engage in the development and operation of a rock dust mill. The main purpose of the rock dust mill will be to manufacture and sell rock dust. We consolidate MAC’s financial results in accordance with FIN 46R. Based on the guidance in FIN 46R, we concluded that MAC is a variable interest entity and that we are the primary beneficiary. House’s portion of MAC’s net loss was $96,000 for the 2006 Period and is recorded as minority interest on our condensed consolidated income statement.

Our 2006 Period Segment Adjusted EBITDA increased $10.0 million, or 4.9%, to $205.7 million from the 2005 Period Segment Adjusted EBITDA of $196.2 million. Segment Adjusted EBITDA, tons sold, coal sales, operating revenues and Segment Adjusted EBITDA Expense by segment are as follows (in thousands):


	Nine Months Ended September 30,
	2006		2005		Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	146,606	$	138,954	$	7,652		5.5	%
Central Appalachia		30,761		29,214		1,547		5.3	%
Northern Appalachia		24,172		27,046		(2,874	)	(10.6	)%
Other and Corporate		4,206		968		3,238		(3	)

Total Segment Adjusted EBITDA (1)	$	205,745	$	196,182	$	9,563		4.9	%

Tons sold
Illinois Basin		12,642		12,172		470		3.9	%
Central Appalachia		2,674		2,345		329		14.0	%
Northern Appalachia		2,501		2,460		41		1.7	%
Other and Corporate		19		—		19		(3	)

Total tons sold		17,836		16,977		859		5.1	%

Coal sales
Illinois Basin	$	425,743	$	374,780	$	50,963		13.6	%
Central Appalachia		136,951		108,171		28,780		26.6	%
Northern Appalachia		75,576		77,658		(2,082	)	(2.7	)%
Other and Corporate		14,257		3		14,254		(3	)

Total coal sales	$	652,527	$	560,612	$	91,915		16.4	%

Other sales and operating revenues
Illinois Basin	$	16,579	$	19,100	$	(2,521	)	(13.2	)%
Central Appalachia		238		186		52		28.0	%
Northern Appalachia		1,565		1,677		(112	)	(6.7	)%
Other and Corporate		3,499		2,704		795		29.4	%

Total other sales and operating revenues	$	21,881	$	23,667	$	(1,786	)	(7.5	)%

Segment Adjusted EBITDA Expense
Illinois Basin	$	295,716	$	254,926	$	40,790		16.0	%
Central Appalachia		106,427		79,143		27,284		34.5	%
Northern Appalachia		52,969		52,288		681		1.3	%
Other and Corporate		13,551		1,740		11,811		(3	)

Total Segment Adjusted EBITDA Expense (2)	$	468,663	$	388,097	$	80,566		20.8	%

(1)

(2)	Segment Adjusted EBITDA Expense includes operating expenses, outside purchases and other income. Pass through transportation expenses are excluded.

(3)	Percentage increase was significantly greater than 100%

Illinois Basin – Segment Adjusted EBITDA for the 2006 Period, as defined in reference (1) to the table above, increased 5.5%, to $146.6 million from the 2005 Period Segment Adjusted EBITDA of $139.0 million. The increase of $7.6 million was primarily attributable to increased coal sales which rose by $51.0 million, or 13.6%, to $425.7 million during the 2006 Period as compared to $374.8 million in the 2005 Period. Increased coal sales in the 2006 Period reflects a higher average coal sales price per ton which increased $2.89 per ton to $33.68 per ton (contributing $36.5 million of the increase in coal sales) and increased tons sold of 470,000 in the 2006 Period (which contributed $14.5 million of the increase in coal sales). Other sales and operating revenues decreased $2.5 million, primarily due to a decrease in rent and service fees associated with decreased synfuel volumes at third-party coal synfuel facilities. Total Segment Adjusted EBITDA Expense for the 2006 Period increased 16.0 % to $295.7 million from $254.9 million in the 2005 Period. On a per ton sold basis, the 2006 Period Segment Adjusted EBITDA Expense rose to $23.39 per ton, an increase of 11.7% over the 2005 Period Segment Adjusted EBITDA Expense per ton of $20.94 per ton. The increase in the 2006 Period Segment Adjusted EBITDA Expense compared to the 2005 Period primarily reflects the impact of cost increases described above under consolidated operating expenses. Illinois Basin costs have been negatively impacted by high cost production at the Elk Creek mine which emerged from development in the second quarter of 2006, but has not yet reached full production capacity.

Central Appalachia – Segment Adjusted EBITDA for the 2006 Period, as defined in reference (1) to the table above, increased $1.5 million, or 5.3%, to $30.8 million as compared to the 2005 Period Segment Adjusted EBITDA of $29.2 million. The increase was primarily attributable to increased coal sales of $28.8 million, reflecting a higher average coal sales price per ton of $51.21 in the 2006 Period, an increase of $5.08 per ton over the 2005 Period average coal sales price per ton, (which contributed $13.6 million of the increase in coal sales) and increased tons sold of 329,000 tons in the 2006 Period (which contributed $15.2 million of the increase in coal sales) partially offset by an increase in Segment Adjusted EBITDA Expense for the 2006 Period of 34.5% to $106.4 million from $79.1 million in the 2005 Period. The increase in the 2006 Period Segment Adjusted EBITDA Expense compared to the 2005 Period primarily reflects the increase in tons sold. On a per ton sold basis, the 2006 Period Segment Adjusted EBITDA Expense rose $6.05 per ton reflecting the impact of cost increases described above under consolidated operating expenses. Additionally, Central Appalachia costs have been negatively impacted by high cost production of ramping to full production in Pontiki’s Van Lear seam and transitioning to the Albridge Branch area of the Pond Creek seam. The production increase was primarily attributable to the negative impact of the MC Mining Fire Incident on production in the 2005 Period.

Northern Appalachia – Segment Adjusted EBITDA for the 2006 Period, as defined in reference (1) to the table above, decreased $2.8 million, or 10.6%, to $24.2 million as compared to the 2005 Period Segment Adjusted EBITDA of $27.0 million. The decrease was primarily attributable to a $2.1 million reduction of coal sales reflecting a lower average sales price per ton of $1.36 to $30.22 per ton in the 2006 Period (which contributed $3.4 million of the decrease in coal sales) partially offset by an increase in tons sold of 41,000 (resulting in a $1.3 million increase). The lower average sales price was primarily attributable to fewer tons sold into the higher priced export market during the 2006 Period. The 2006 and 2005 Period Segment Adjusted EBITDA Expense was comparable for both periods.

A reconciliation of Segment Adjusted EBITDA to net income is as follows (in thousands):


	Nine Months Ended September 30,
	2006			2005
Segment Adjusted EBITDA	$	205,745		$	196,182

General & administrative		(21,640	)		(29,067	)
Depreciation, depletion and amortization		(48,283	)		(40,822	)
Interest expense, net		(6,933	)		(9,685	)
Income taxes		(1,658	)		(2,256	)
Minority interest		96			—
Cumulative effect of accounting change		112			—

Net income	$	127,439		$	114,352

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 September 30, 2006, 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 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.

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 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 estimate of our expenses and losses, with an update through July 31 2005. Partial payments of $4.0 million and $12.2 million were received, during the nine months ended September 30, 2006 and the year ended December 31, 2005, respectively. These amounts are net of the 2005 Deductibles and 2005 Co-Insurance. 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. On March 23, 2006, we filed a third partial proof of loss for the period through July 31, 2005 of $4.0 million. Currently, we continue to evaluate our potential insurance recoveries under the applicable insurance policies in the following areas:

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Cash provided by operating activities was $184.8 million for the 2006 Period compared to $151.6 million for the 2005 Period. The increase in cash provided by operating activities was principally attributable to a combination of a lower period-to-period increase in working capital in the 2006 Period compared to the 2005 Period and an increase in net income. Total working capital changes include a reduced use of cash attributable to accounts receivable and other receivables partially offset by an increased use of cash for inventory in the 2006 Period compared to the 2005 Period. The 2005 Period included an increase in accounts receivable related to higher trade accounts receivable attributable to slower payments from certain customers.

Net cash used in investing activities was $95.7 million for the 2006 Period compared to $78.9 million for the 2005 Period. The increase is primarily attributable to an increase in capital expenditures associated with our Elk Creek and Mountain View mines, the acquisition of coal reserves for our River View mine and additional reserves acquired in Eastern Kentucky. We are currently estimating total capital expenditures in 2006 to range from approximately $175.0 million to $190.0 million. We expect to fund these capital expenditures with available cash and marketable securities on hand, future cash generated from operations and/or borrowings available under the revolving credit facility. The increase in net cash used in investing activities attributable to increased capital expenditures was partially offset by increased proceeds from marketable securities, net of marketable securities purchases, during the 2006 Period.

Net cash used in financing activities primarily was $84.3 million for the 2006 Period compared to $65.1 million for the 2005 Period. The increase primarily was attributable to increased distributions to partners in the 2006 Period.

Capital Expenditures

Capital expenditures increased to $142.0 million in the 2006 Period from $80.6 million in the 2005 Period. See discussion of “Cash Flows” above concerning the increase in capital expenditures. Capital expenditures include items received but not yet paid, which is disclosed as a non-cash investing activity, purchase of property, plant and equipment in “Item 1, Financial Statements (Unaudited) – Condensed Consolidated Statements of Cash Flows.”

Notes Offering and Credit Facility

Our Intermediate Partnership has $144.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in eight remaining equal annual installments of $18.0 million with interest payable semiannually (Senior Notes). On April 13, 2006, our Intermediate Partnership entered into a $100.0 million revolving credit facility (ARLP Credit Facility), which expires in 2011. The ARLP Credit Facility replaced an $85.0 million credit facility that would have expired September 2006. Borrowings under the ARLP Credit Facility bear interest based on a floating base rate plus an applicable margin. The applicable margin is based on a leverage ratio of our Intermediate Partnership, as computed from time to time. The initial applicable margin for borrowings under the ARLP Credit Facility is 0.875% with respect to London Interbank Offered Rate (LIBOR) borrowings. Letters of credit can be issued under the ARLP Credit Facility not to exceed $50.0 million. Outstanding letters of credit reduce amounts available under the ARLP Credit Facility. At September 30, 2006, we had letters of credit of $10.8 million outstanding under the ARLP Credit Facility. We had no borrowings outstanding under the ARLP Credit Facility at September 30, 2006.

The Senior Notes and ARLP Credit Facility are guaranteed by all of the subsidiaries of our Intermediate Partnership. The Senior Notes and ARLP Credit Facility contain various restrictive and affirmative covenants, affecting our Intermediate Partnership and its subsidiaries restricting, among other things, the amount of distributions by our intermediate partnership, the incurrence of additional indebtedness and liens, the sale of assets, the making of investments, the entry into mergers and consolidations and the entry into transactions with affiliates, in each case subject to various exceptions. The Senior Notes and the ARLP Credit Facility also require the Intermediate Partnership to remain in control of a certain amount of mineable coal based on a ratio of the amount of total mineable tons controlled by the Intermediate Partnership relative to its annual production. In addition, the Senior Notes and the ARLP Credit Facility require the Intermediate Partnership to comply with certain financial ratios, including a maximum leverage ratio and a minimum interest coverage ratio. We were in compliance with the covenants of both the ARLP Credit Facility and Senior Notes at September 30, 2006.

We have previously entered into and have maintained specific agreements with two banks to provide additional letters of credit in an aggregate amount of $31.0 million to maintain surety bonds to secure our obligations for reclamation liabilities and workers’ compensation benefits. At September 30, 2006, we had $26.6 million in letters of credit outstanding under these agreements. Our special general partner guarantees $5.0 million of these outstanding letters of credit.

RELATED PARTY TRANSACTIONS

We have continuing related party transactions with our managing general partner, AHGP, and our special general partner, including our special general partner’s affiliates. These related party transactions relate principally to the provision of administrative services by our managing general partner, administrative services by us to AHGP, Alliance Resource Holdings II, Inc. (ARH II) and their respective affiliates, mineral and equipment leases with our special general partner and its affiliates, and guarantees from our special general partner for letters of credit.

Please read our Annual Report on Form 10-K for the year ended December 31, 2005, “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.

In connection with the closing of the IPO of AHGP (see “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Summary” above), we entered into an Administrative Services Agreement between our managing general partner, our operating subsidiary, AHGP and ARH II. Under the Administrative Services Agreement, certain of our own personnel, including executive officers, are providing administrative services to our managing general partner, AHGP, AGP, ARH II and their respective affiliates. We will be reimbursed for services rendered by our employees on behalf of these affiliates as provided under the Administrative Services Agreement. We billed and recognized administrative service revenue under these agreements of $218,000 and $696,000, respectively, for the three and nine months ended September 30, 2006. Concurrently, AHGP, AGP and our managing general partner joined as parties to our Omnibus Agreement, which addresses areas of non-competition between AHGP and us.

Because the Administrative Services Agreement described above was a related-party transaction, it was reviewed by the Board of Directors of our managing general partner and its conflicts committee. Based upon this review, the conflicts committee 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 transaction as fair and reasonable to us and our limited partners.

NEW ACCOUNTING STANDARDS

In November 2004, the FASB issued SFAS No. 151, Inventory Costs (SFAS No. 151). 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. Our adoption of SFAS No. 151 on January 1, 2006 did not have a significant impact on our consolidated financial statements.

Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No. 123R, Shared-Based Payment, using the “modified prospective” transition method and, therefore, did not restate prior period results.

In March 2005, the FASB issued EITF No. 04-6, Accounting for Stripping Costs in the Mining Industry (EITF No. 04-6), 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, our adoption of EITF No. 04-6, effective January 1, 2006 did not have a material impact on our consolidated financial statements.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (FIN 48). This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. The interpretation prescribes a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. We are currently in the process of assessing the provisions of FIN 48, but do not expect the adoption of FIN 48 to have a material impact on our consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS No. 157). This standard defines fair value, establishes a framework for measuring fair value in accounting principles generally accepted in the United States of America, and expands disclosure about fair value measurements. SFAS No. 157 applies under other accounting standards that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurement. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the requirements of SFAS No. 157 and have not yet determined the impact on our consolidated financial statements.

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R) (SFAS No. 158). SFAS No. 158 requires an employer to recognize the overfunded or underfunded

status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability on its statement of financial position. SFAS No. 158 also requires an employer to recognize changes in that funded status in the year in which the changes occur through comprehensive income. In addition, SFAS No. 158 requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position. SFAS No. 158 requirements to recognize the funded status of a benefit plan and new disclosure requirements are effective as of December 31, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. We do not expect the adoption of SFAS No. 158 to have a material impact on our consolidated financial statements at December 31, 2006.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements (SAB 108), which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. SAB 108 is effective as of December 31, 2006. We are currently in the process of assessing SAB 108 but do not expect the adoption of SAB 108 to have a material impact on our consolidated financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We have significant long-term coal supply agreements. Virtually all of our long-term coal supply agreements are subject to price adjustment provisions, which permit an increase or decrease periodically in the contract price to principally reflect changes in specified price indices or items such as taxes, royalties or actual production costs.

Almost 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. At the current time, we do not have any interest rate, foreign currency exchange rate or commodity price-hedging transactions outstanding.

Borrowings under the ARLP Credit Facility are at variable rates and, as a result, we have interest rate exposure. Our earnings are not materially affected by changes in interest rates. We had no borrowings outstanding under the ARLP Credit Facility at September 30, 2006.

As of September 30, 2006, the estimated fair value of the Senior Notes was approximately $159.6 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, 2005.

ITEM 4. CONTROLS AND PROCEDURES

We maintain controls and procedures designed to ensure that we are able to collect the information we are required to disclose in the reports we file with the SEC, and to process, summarize and disclose this information within the time periods specified in the rules of the SEC. An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act) was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive and Chief Financial Officers. Based on an evaluation of our disclosure controls and procedures as of the end of the period covered by this report conducted by our management, with the participation of our Chief Executive and Chief Financial Officers, our Chief Executive and Chief Financial Officers believe the design and operation of these controls and procedures

are effective to ensure that the ARLP Partnership is able to collect, process and disclose the information it is required to disclose in the reports it files with the SEC within the required time periods, and during the quarterly period ended September 30, 2006, there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements. 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:

•

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

•

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

•

risks associated with the expansion of our operations and properties;

•

deregulation of the electric utility industry or the effects of any adverse change in the 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 or breaches to existing contracts;

•

customer delays or defaults in making payments;

•

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

•

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

•

greater than expected increases in raw material costs;

•

greater than expected shortage of skilled labor;

•

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

•

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

•

greater than expected environmental regulation, costs and liabilities;

•

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

•

risks associated with major mine-related accidents, such as mine fires, or interruptions;

•

results of litigation;

•

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

•

a loss or reduction of the direct or indirect benefit from certain state and federal tax credits, including non-conventional source fuel tax credits; and

•

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

If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind the risk factors described in “Risk Factors” below. The risk factors could also cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

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

•

in this Quarterly Report on Form 10-Q;

•

other reports filed by us with the SEC;

•

our press releases; and

•

written or oral statements made by us or any of our officers or other 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, 2005.

On April 24, 2006, we were served with a complaint from Mr. Ned Comer, et al., who we refer to as the plaintiffs, alleging that approximately 40 oil and coal companies, including us, which we refer to as the defendants, are liable to the plaintiffs for tortiously causing damage to plaintiffs’ property in Mississippi. The plaintiffs allege that the defendants’ greenhouse gas emissions caused global warming and resulted in the increase in the destructive capacity of Hurricane Katrina. We believe this complaint is without merit and we do not believe that an adverse decision in this litigation matter, if any, will have a material adverse effect on our business, financial position or results of operations.

ITEM 1A. RISK FACTORS

In addition to the other information set forth in the Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2005, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not our only risks. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial based on current knowledge and factual circumstances and, if such knowledge or factors change, also may materially adversely affect our business, financial condition and/or operating results in the future.

Other risk factors to consider are as follows:

•

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. The transactions surrounding the IPO, which closed on May 15, 2006, represented a sale or exchange of approximately 42.3% of the total interests in our capital and profits interests. We believe, and will take the position, that the transactions surrounding the IPO, together with all other common units sold within the prior 12-month period, represent a sale or exchange of 50% or more of the total interest in our capital and profits interests. The termination of the partnership for federal income tax purposes will result, among other things, in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income for the year in which the termination occurs. The impact of this termination to our unitholders is reflected in the amount of taxable income we expect to be allocated to unitholders as a result of an investment in our common units. Although the amount of increase cannot be estimated because it depends upon numerous factors including the timing of the termination, the amount could be material. The termination of the partnership will not affect our classification as a partnership for federal income tax purposes, but instead, we will be treated as a new partnership for tax purposes. As a new partnership, we must make new tax elections and could be subject to penalties if we are unable to substantiate that a termination occurred.

•

During September 2006, we completed our annual property and casualty insurance renewal with various insurance coverages effective as of October 1, 2006. Available capacity for underwriting property insurance continues to be limited as a result of insurance carrier losses in the mining industry and our recent insurance claims history (e.g., MC Mining Fire Incident and Dotiki Fire Incident). As a result, we have elected to retain a participating interest along with our insurance carriers at an average rate of approximately 14.7% in the overall $75.0 million commercial property program representing 35% of the primary $30.0 million layer and 2.5% of the second layer representing $20.0 million in excess of the $30.0 million primary layer. We do not participate in the third layer of $25.0 million excess of $50.0 million. The 14.7% participation rate for this year’s renewal exceeds the approximate 10% participation level from last year. The aggregate maximum limit in the commercial property program is $75.0 million per occurrence of which we would be responsible for a maximum amount of $11.0 million for each occurrence, excluding a $1.5 million deductible for property damage, a $5.0 million aggregate deductible for extra expense and a 60-day waiting period for business interruption. As a result of our increased participation in the property program and higher deductible levels, property premiums paid to the insurance carriers were reduced by approximately 14.5%. 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.

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 9, 2006, 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, 2006, 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, 2006, 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, 2006, 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, 2006.


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